~~Energy Sales~~

~~Changes~~the CO₂ pipeline facilities, AFUDC, and certain general exceptions (Cost Cap Exceptions). The combined cycle and associated common facilities portions of the Kemper County energy facility were placed in ~~revenues are influenced heavily by~~service in August 2014. In December 2015, the ~~change~~Mississippi PSC issued an order (In-Service Asset Rate Order), authorizing rates that provided for the recovery of approximately $126 million annually related to the assets previously placed in service.

On June 21, 2017, the ~~volume~~Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of the related costs (Kemper Settlement Docket).

Total
KWHs

Total KWH
Percent Change

Weather-Adjusted
Percent Change
2015 2015 2014 2015* 2014
(in billions)
Residential 52.1
(2.3 )% 5.5 % 0.4 % — %
Commercial 53.5
0.5
1.3
0.9
(0.4 )
Industrial 54.0
(0.4 ) 3.3
(0.3 ) 3.3
Other 0.9
(1.4 ) 0.9
(1.3 ) 0.7
Total retail 160.5
(0.7 ) 3.3
0.3 % 0.9 %
Wholesale 30.5
(7.0 ) 21.7

Total energy sales 191.0
(1.8 )% 6.0 %



*	~~In the first quarter 2015, Mississippi Power updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have~~ a significant impact on net income. The KWH sales variances in the above table reflect an adjustment to the estimated allocation of Mississippi Power's unbilled 2014 KWH sales among customer classes that is consistent with the actual allocation in 2015. Without this adjustment, 2015 weather-adjusted commercial sales increased 0.8% and industrial KWH sales decreased 0.4% as compared to the corresponding period in 2014.

~~Changes in retail energy sales are generally the~~ result of changes in ~~electricity usage by customers, changes~~the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in ~~weather,~~June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and ~~changes~~lignite mine.

On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement). The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6%, excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with Mississippi Power's Performance Evaluation Plan (PEP), excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in the ~~number of customers. Retail~~Kemper County energy ~~sales decreased 1.2 billion KWHs~~facility requested for inclusion in ~~2015 as compared to the prior year. This decrease~~rate base, which was ~~primarily the result of milder weather~~recorded in the ~~first~~fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).

Under the Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date. On February 12, 2018, Mississippi Power made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) Mississippi Power to file a reserve margin plan with the Mississippi PSC by August 2018.

During the third and fourth quarters of ~~2015~~2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as ~~compared~~well as the charge associated with the Kemper Settlement Agreement. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power has begun efforts to dispose of or abandon the mine and gasifier-related assets.

Total pre-tax charges to income related to the corresponding periods in 2014 and decreased customer usage, partially offset by customer growth. Weather-adjusted commercial KWH sales increased primarily due to customer growth and increased customer usage. Weather-adjusted residential KWH sales increased primarily due to customer growth, partially offset by decreased customer usage.~~Household income, one~~Kemper County energy facility were $3.4 billion ($2.4 billion after tax) for the year ended December 31, 2017. In the aggregate, since the Kemper County energy facility project started, Mississippi Power has incurred charges of the primary drivers of residential customer usage, had modest growth in 2015. The decrease in industrial KWH energy sales was primarily due to decreased sales in the primary metals, chemicals, and paper sectors, partially offset by increased sales in the transportation, stone, clay, and glass, pipeline, lumber, and petroleum sectors. A strong dollar, low oil prices, and weak global economic growth conditions constrained the industrial sector in 2015.$6.2 billion ($4.1 billion after tax) through December 31, 2017.

Retail energy sales increased 5.2 billion KWHs in 2014 as compared to the prior year. This increase was primarily the result of colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and customer growth, partially offset by a decrease in customer usage. The increase in industrial KWH energy sales was primarily due to increased sales in the primary metals, chemicals, paper, non-manufacturing, transportation, and stone, clay, and glass sectors. Weather-adjusted commercial KWH energy sales decreased primarily due to decreased customer usage, partially offset by customer growth. Weather-adjusted residential KWH energy sales were flat compared to the prior year asAs a result of ~~customer growth offset by decreased customer usage. Household income, one~~the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.

See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.

Plant Vogtle Units 3 and 4 Status

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the ~~primary drivers~~two AP1000 nuclear units (with electric generating capacity of ~~residential customer usage, was flat in 2014.~~

~~See "Electric Operating Revenues" above for a discussion of significant changes in wholesale revenues~~approximately 1,100 MWs each) and related facilities to ~~changes in price and KWH sales.~~begin. Until March 2017, construction on Plant Vogtle Units

~~Fuel and Purchased Power Expenses~~

Fuel costs constitute the single largest expense for the electric utilities. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the electric utilities purchase a portion of their electricity needs from the wholesale market.

~~II-18~~

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

~~Details~~3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. On March 29, 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 Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired on July 27, 2017 when the Vogtle Services Agreement became effective. In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, Georgia Power filed its seventeenth VCM report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor. On December 21, 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction.

Georgia Power expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. Georgia Power's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement) and certain refunds to customers ordered by the Georgia PSC (Customer Refunds)). Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.

See Note 3 to the financial statements under "Nuclear Construction" for additional information.

Earnings

Consolidated net income attributable to Southern Company was $842 million in 2017, a decrease of $1.6 billion, or 65.6%, from the prior year. The decrease was primarily due to pre-tax charges of $3.4 billion ($2.4 billion after tax) related to the Kemper IGCC at Mississippi Power. Also contributing to the change were increases of $240 million in net income from Southern Company Gas (excluding the impact of $111 million in additional expense related to the Tax Reform Legislation) reflecting the 12-month period in 2017 compared to the six-month period following the Merger closing on July 1, 2016, $264 million related to net tax benefits from the Tax Reform Legislation, higher retail electric revenues resulting from increases in base rates partially offset by milder weather and lower customer usage, and increases in renewable energy sales at Southern Power. These increases were partially offset by higher interest and depreciation and amortization.

Consolidated net income attributable to Southern Company was $2.4 billion in 2016, an increase of $81 million, or 3.4%, from the prior year. Consolidated net income increased by $114 million as a result of earnings from Southern Company Gas, which was acquired on July 1, 2016. Also contributing to the increase were higher retail electric revenues resulting from non-fuel retail rate increases and warmer weather, primarily in the third quarter 2016, as well as the 2015 correction of a Georgia Power billing error, partially offset by accruals in 2016 for expected refunds at Alabama Power and Georgia Power. Additionally, the increase was due to increases in income tax benefits and renewable energy sales at Southern Power. These increases were partially offset by higher interest expense, non-fuel operations and maintenance expenses, depreciation and amortization, lower wholesale capacity revenues, and higher estimated losses associated with the Kemper IGCC.

See Note 12 to the financial statements under "Southern Company – Merger with Southern Company Gas" for additional information regarding the Merger.

Basic EPS was $0.84 in 2017, $2.57 in 2016, and $2.60 in 2015. Diluted EPS, which factors in additional shares related to stock-based compensation, was $0.84 in 2017, $2.55 in 2016, and $2.59 in 2015. EPS for 2017 was negatively impacted by $0.04 per share as a result of an increase in the average shares outstanding. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for additional information.

Dividends

Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $2.30 in 2017, $2.22 in 2016, and $2.15 in 2015. In January 2018, Southern Company declared a quarterly dividend of 58 cents per share. This is the 281st consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. For 2017, the dividend payout ratio was 273% compared to 86% for 2016. The increase was due to a significant reduction in earnings resulting from charges related to the Kemper IGCC. See "Earnings" and RESULTS OF OPERATIONS – "Electricity Business – Estimated Loss on Kemper IGCC" herein and Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

RESULTS OF OPERATIONS

Discussion of the results of operations is divided into three parts – the Southern Company system's ~~generation~~primary business of electricity sales, its gas business, and ~~purchased power~~its other business activities.



	Amount
	2017			2016			2015
	(in millions)
Electricity business	$	878		$	2,571		$	2,401
Gas business	243			114			—
Other business activities	(279		)	(237		)	(34		)
Net Income	$	842		$	2,448		$	2,367

Electricity Business

Southern Company's electric utilities generate and sell electricity to retail and wholesale customers.

A condensed statement of income for the electricity business follows:



	Amount			Increase (Decrease) from Prior Year
	2017			2017			2016
	(in millions)
Electric operating revenues	$	18,540		$	599		$	499
Fuel	4,400			39			(389		)
Purchased power	863			113			105
Cost of other sales	69			11			58
Other operations and maintenance	4,340			(183		)	231
Depreciation and amortization	2,457			224			213
Taxes other than income taxes	1,063			24			44
Estimated loss on Kemper IGCC	3,362			2,934			63
Total electric operating expenses	16,554			3,162			325
Operating income	1,986			(2,563		)	174
Allowance for equity funds used during construction	152			(48		)	(26		)
Interest expense, net of amounts capitalized	1,011			80			157
Other income (expense), net	(83		)	(8		)	(43		)
Income taxes	82			(1,009		)	(235		)
Net income	962			(1,690		)	183
Less:
Dividends on preferred and preference stock of subsidiaries	38			(7		)	(9		)
Net income attributable to noncontrolling interests	46			10			22
Net Income Attributable to Southern Company	$	878		$	(1,693	)	$	170

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Electric Operating Revenues

Electric operating revenues for 2017 were $18.5 billion, reflecting a $599 million increase from 2016. Details of electric operating revenues were as follows:

2015 2014 2013
Total generation (billions of KWHs)
187
191
179
Total purchased power (billions of KWHs)
13
12
12
Sources of generation (percent) —

Coal 34
42
39
Nuclear 16
16
17
Gas 46
39
40
Hydro 3
3
4
Other Renewables 1
—
—
Cost of fuel, generated (cents per net KWH) —

Coal 3.55
3.81
4.01
Nuclear 0.79
0.87
0.87
Gas 2.60
3.63
3.29
Average cost of fuel, generated (cents per net KWH)
2.64
3.25
3.17
Average cost of purchased power (cents per net KWH)*
6.11
7.13
5.27



*	~~Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.~~

~~In 2015, total fuel and purchased power expenses were $5.4 billion, a decrease of $1.3 billion,~~



	Amount
	2017			2016
	(in millions)
Retail electric — prior year	$	15,234		$	14,987
Estimated change resulting from —
Rates and pricing	508			427
Sales decline	(71		)	(35		)
Weather	(281		)	153
Fuel and other cost recovery	(60		)	(298		)
Retail electric — current year	15,330			15,234
Wholesale electric revenues	2,426			1,926
Other electric revenues	681			698
Other revenues	103			83
Electric operating revenues	$	18,540		$	17,941
Percent change	3.3		%	2.9		%

Retail electric revenues increased $96 million, or ~~19.2%~~0.6%, in 2017 as compared to the prior year. The ~~decrease was primarily the result of a $1.1 billion decrease~~significant factors driving this change are shown in the ~~average cost of fuel~~preceding table. The increase in rates and ~~purchased power~~pricing in 2017 was primarily due to ~~lower coal~~a Rate RSE increase at Alabama Power effective in January 2017, the recovery of Plant Vogtle Units 3 and ~~natural gas prices~~4 construction financing costs under the NCCR tariff at Georgia Power, and ~~a $137 million net decrease in the volume of KWHs generated and purchased due to milder weather in the first and fourth quarters of 2015.~~

~~In 2014, total fuel and purchased power expenses were $6.7 billion,~~ an increase ~~of $706~~in retail base rates effective July 2017 at Gulf Power. See Note 3 to the financial statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.

Retail electric revenues increased $247 million, or ~~11.8%~~1.6%, in 2016 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2016 was primarily due to increases in base tariffs at Georgia Power under the ~~result~~2013 ARP and the NCCR tariff and increased revenues at Alabama Power under Rate CNP Compliance, all effective January 1, 2016. Also contributing to the increase in rates and pricing for 2016 was the 2015 correction of an error affecting billings since 2013 to a ~~$422 million increase~~small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing at Georgia Power and the implementation of rates at Mississippi Power for certain Kemper County energy facility in-service assets, effective September 2015. These increases were partially offset by accruals in 2016 for expected refunds at Alabama Power and Georgia Power. See Note 3 to the financial statements under "Kemper County Energy Facility – Rate Recovery" for additional information.

See Note 3 to the financial statements under "Regulatory Matters – Alabama Power – Rate RSE" and " – Rate CNP Compliance" and "Nuclear Construction" and Note 1 to the financial statements under "General" for additional information. Also see "Energy Sales" below for a discussion of changes in the volume of ~~KWHs generated~~energy sold, including changes related to sales decline and weather.

Electric rates for the traditional electric operating companies 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 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 consist of PPAs primarily ~~due~~with investor-owned utilities and electric cooperatives 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 ~~increased demand resulting from colder weather in~~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 ~~first quarter 2014 and warmer weather in the second and third quarters 2014 as~~market prices of wholesale energy compared to the ~~corresponding periods~~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 ~~2013 and a $286 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices.~~

~~Fuel and purchased power~~ energy ~~transactions at the traditional operating companies~~revenues that are ~~generally offset~~driven by fuel ~~revenues~~prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. ~~See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Retail Fuel Cost Recovery" herein for additional information. Fuel expenses incurred under Southern Power's~~Energy sales from solar and wind PPAs ~~are generally the responsibility of the counterparties and~~ do not ~~significantly impact net income.~~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

~~Fuel~~

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

result, the Company'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. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales 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.

Wholesale electric revenues from power sales were as follows:



	2017		2016		2015
	(in millions)
Capacity and other	$	838	$	771	$	875
Energy	1,588		1,155		923
Total	$	2,426	$	1,926	$	1,798

In ~~2015, fuel expense was $4.8 billion, a decrease of $1.3 billion,~~2017, wholesale revenues increased $500 million, or ~~20.9%~~26.0%, as compared to the prior ~~year.~~year due to a $433 million increase in energy revenues and a $67 million increase in capacity revenues, primarily at Southern Power. The ~~decrease~~increase in energy revenues was primarily due to increases in renewable energy sales arising from new solar and wind facilities and non-PPA revenues from short-term sales. The increase in capacity revenues was primarily due to a ~~28.4% decrease in the average cost of~~PPA related to new natural gas ~~per KWH generated, a 19.2% decrease in the volume of KWHs generated by coal,~~facilities and ~~a 6.8% decrease in the average cost of coal per KWH generated, partially offset by a 15.9% increase in the volume of KWHs generated by natural gas.~~additional customer capacity requirements.

In ~~2014, fuel expense was $6.0 billion, an increase of $495~~2016, wholesale revenues increased $128 million, or ~~9.0%~~7.1%, as compared to the prior ~~year.~~year due to a $232 million increase in energy revenues, partially offset by a $104 million decrease in capacity revenues. The increase in energy revenues was primarily due to ~~a 12.7% increase~~increases in ~~the volume of KWHs generated by coal, a 10.3% increase in the average cost of natural gas per KWH generated,~~short-term sales and ~~a 30.7% decrease in the volume of KWHs generated by hydro facilities resulting from less rainfall,~~renewable energy sales at Southern Power, partially offset by ~~a 5.0%~~lower fuel prices. The decrease in capacity revenues was primarily due to the ~~average cost~~expiration of ~~coal per KWH generated.~~wholesale contracts at Georgia Power and Gulf Power, the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, and unit retirements at Georgia Power, partially offset by an increase due to a new wholesale contract at Alabama Power in the first quarter 2016.

Purchased Power



Facility/Source	Counterparty	MWs	Contract Term
NCEMC	NCEMC	100	through Dec. 2021

I-6

Table of Contents Index to Financial Statements

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" and "Acquisitions" of Southern Power in Item 7 herein and Note 11 to the financial statements of Southern Power in Item 8 herein for additional information.

For the year ended December 31, 2017, approximately 11.3% of Southern Power's revenues were derived from Georgia Power. Southern Power actively pursues replacement PPAs prior to the expiration of its current PPAs and anticipates that the revenues attributable to one customer may be replaced by revenues from a new customer; however, the expiration of any of Southern Power's current PPAs without the successful remarketing of a replacement PPA could have a material negative impact on Southern Power's earnings but is not expected to have a material impact on Southern Company's earnings.

Southern Company Gas

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. Southern Company Gas is also involved in several other businesses that are complementary to the distribution of natural gas, including gas marketing services, wholesale gas services, and gas midstream operations.

Gas distribution operations, the largest segment of Southern Company Gas' business, operates, constructs, and maintains 82,000 miles of natural gas pipelines and 14 storage facilities, with total capacity of 158 Bcf, to provide natural gas to residential, commercial, and industrial customers. Gas distribution operations serves approximately 4.6 million customers across seven states and has rates of return that are regulated by each individual state in return for exclusive franchises.

On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings Inc., entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. As of December 31, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.3 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and, as a result, a deferred tax liability has not yet been provided. Through the completion of the asset sales, Southern Company Gas intends to invest less than $0.1 billion in capital additions required for ordinary business operations of these assets. The completion of each asset sale is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey Board of Public Utilities, and, with respect to the sale of Elkton Gas, the Maryland PSC. Southern Company Gas and South Jersey Industries, Inc. made joint filings on December 22, 2017 and January 16, 2018 with the New Jersey Board of Public Utilities and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018. The ultimate outcome of these matters cannot be determined at this time.

Gas marketing services is comprised of SouthStar Energy Services, LLC (SouthStar) and Nicor Energy Services Company (doing business as Pivotal Home Solutions) and provides natural gas commodity and related services to customers in competitive markets or markets that provide for customer choice. SouthStar, serving approximately 774,000 natural gas commodity customers, markets gas to residential, commercial, and industrial customers and offers energy-related products that provide natural gas price stability and utility bill management. Pivotal Home Solutions, serving approximately 1.2 million service contracts, provides a suite of home protection products and services that offers homeowners predictability regarding their energy service delivery, systems, and appliances.

Wholesale gas services consists of Sequent Energy Management, L.P. and engages in natural gas storage and gas pipeline arbitrage and provides natural gas asset management and related logistical services to most of the natural gas distribution utilities as well as non-affiliate companies.

Gas midstream operations includes joint ventures in pipeline investments (including a 50% ownership interest in Southern Natural Gas Company, L.L.C. and two significant pipeline construction projects) as well as a 50% joint ownership in a significant pipeline project and wholly-owned natural gas storage facilities that enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas. Southern Natural Gas Company, L.L.C. is the owner of a 7,000-mile pipeline connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee.

For additional information on Southern Company Gas' business activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Business Activities" and – FUTURE EARNINGS POTENTIAL of Southern Company Gas in Item 7 herein.

Other Businesses

PowerSecure, which was acquired by Southern Company in May 2016, provides products and services in the areas of distributed energy infrastructure, energy efficiency, and utility infrastructure.

I-7

Table of Contents Index to Financial Statements

Southern Holdings is an intermediate holding subsidiary, primarily for Southern Company's investments in leveraged leases and energy-related funds and companies, and also for other electric and natural gas products and services.

Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public. Southern Linc delivers multiple wireless communication options including push to talk, cellular service, text messaging, wireless internet access, and wireless data. Its system covers approximately 127,000 square miles in the Southeast. Southern Linc also provides fiber optics services within the Southeast through its subsidiary, Southern Telecom, Inc.

These efforts to invest in and develop new business opportunities may offer potential returns exceeding those of rate-regulated operations. However, these activities often involve a higher degree of risk.

Construction Programs

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. For estimated construction and environmental expenditures for the periods 2018 through 2022, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company, each traditional electric operating company, Southern Power, and Southern Company Gas in Item 7 herein. The Southern Company system's construction program consists of capital investment and capital expenditures to comply with environmental laws and regulations. The traditional electric operating companies also anticipate expenditures associated with ash pond closure and ground water monitoring under the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule), which are reflected in the Southern Company system's asset retirement obligation liabilities. In 2018, the construction program is expected to be apportioned approximately as follows:



	Southern Company system^(a)(b)		Alabama Power		Georgia Power^(a)		Gulf Power		Mississippi Power
	(in billions)
New generation	$	1.3	$	—	$	1.3	$	—	$	—
Environmental compliance^(c)	1.1		0.6		0.5		0.1		—
Generation maintenance	0.9		0.5		0.2		0.1		0.1
Transmission	0.9		0.3		0.5		—		—
Distribution	1.2		0.5		0.5		0.1		0.1
Nuclear fuel	0.3		0.1		0.2		—		—
General plant	0.5		0.2		0.2		—		—
	6.0		2.2		3.3		0.3		0.2
Southern Power^(d)	1.3
Southern Company Gas^(e)	1.7
Other subsidiaries	0.4
Total^(a)	$	9.4	$	2.2	$	3.3	$	0.3	$	0.2


(a)	Totals may not add due to rounding.


(b)	Includes the traditional electric operating companies, Southern Power, and Southern Company Gas, as well as the other subsidiaries. See "Other Businesses" herein for additional information.

(c)

Reflects cost estimates for environmental regulations. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO₂ emissions from fossil-fuel-fired electric generating units or costs associated with closure and groundwater monitoring under the CCR Rule. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company and each traditional electric operating company in Item 7 herein for additional information.


(d)	Includes approximately $0.9 billion for planned expenditures for plant acquisitions and placeholder growth, which may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy.

(e)

Includes costs for ongoing capital projects associated with infrastructure improvement programs for certain natural gas distribution utilities that have been previously approved by their applicable state regulatory agencies. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Infrastructure Replacement Programs and Capital Projects" of Southern Company Gas in Item 7 herein for additional information. See

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"The Southern Company System – Southern Company Gas" herein for additional information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities. Projected capital expenditures of $0.1 billion related to these two natural gas distribution utilities are excluded from the amounts above.

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 the 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; 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 execute its growth strategy.

In addition, the construction program includes the development and construction of new electric generating facilities with designs that have not been previously constructed, which may result in revised estimates during construction. See Note 3 to the financial statements of Southern Company and Georgia Power under "Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 herein for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4.

Also see "Regulation – Environmental Laws and Regulations" herein for additional information with respect to certain existing and proposed environmental requirements and PROPERTIES – "Electric – Jointly-Owned Facilities" and – "Natural Gas – Jointly-Owned Facilities" in Item 2 herein for additional information concerning Alabama Power's, Georgia Power's, and Southern Power's joint ownership of certain generating units and related facilities with certain non-affiliated utilities and Southern Company Gas' joint ownership of a pipeline facility.

Financing Programs

See each of the registrant's MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY in Item 7 herein and Note 6 to the financial statements of each registrant in Item 8 herein for information concerning financing programs.

Fuel Supply

Electric

The traditional electric operating companies' and SEGCO's supply of electricity is primarily fueled by natural gas and coal. Southern Power's supply of electricity is primarily fueled by natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – "Electricity Business – Fuel and Purchased Power Expenses" of Southern Company and MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – "Fuel and Purchased Power Expenses" of each traditional electric operating company in Item 7 herein for information regarding the electricity generated and the average cost of fuel in cents per net KWH generated for the years 2015 through 2017.

The traditional electric operating companies have agreements in place from which they expect to receive substantially all of their 2018 coal burn requirements. These agreements have terms ranging between one and four years. In 2017, the weighted average sulfur content of all coal burned by the traditional electric operating companies was 1.12%. This sulfur level, along with banked and purchased sulfur dioxide allowances, allowed the traditional electric operating companies to remain within limits set by Phase I of the Cross-State Air Pollution Rule (CSAPR) under the Clean Air Act. In 2017, the Southern Company system did not purchase any sulfur dioxide allowances, annual nitrogen oxide emission allowances, or seasonal nitrogen oxide emission allowances from the market. As any additional environmental regulations are proposed that impact the utilization of coal, the traditional electric operating companies' fuel mix will be monitored to help ensure that the traditional electric operating companies remain in compliance with applicable laws and regulations. Additionally, Southern Company and the traditional electric operating companies will continue to evaluate the need to purchase additional emissions allowances, the timing of capital expenditures for emissions control equipment, and potential unit retirements and replacements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company, each traditional electric operating company, and Southern Power in Item 7 herein for additional information on environmental matters.

SCS, acting on behalf of the traditional electric operating companies and Southern Power Company, has agreements in place for the natural gas burn requirements of the Southern Company system. For 2018, SCS has contracted for 510 Bcf of natural gas supply under agreements with remaining terms up to 15 years. In addition to natural gas supply, SCS has contracts in place

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for both firm natural gas transportation and storage. Management believes these contracts provide sufficient natural gas supplies, transportation, and storage to ensure normal operations of the Southern Company system's natural gas generating units.

Alabama Power and Georgia Power have multiple contracts covering their nuclear fuel needs for uranium, conversion services, enrichment services, and fuel fabrication. The uranium, conversion services, and fuel fabrication contracts are for terms of less than 10 years with varying expiration dates. The term lengths for the enrichment services contracts are for less than 15 years with varying expiration dates. Management believes suppliers have sufficient nuclear fuel production capability to permit the normal operation of the Southern Company system's nuclear generating units.

Changes in fuel prices to the traditional electric operating companies are generally reflected in fuel adjustment clauses contained in rate schedules. See "Rate Matters – Rate Structure and Cost Recovery Plans" herein for additional information. Southern Power's natural gas and biomass PPAs generally provide that the counterparty is responsible for substantially all of the cost of fuel.

Alabama Power and Georgia Power have contracts with the United States, acting through the DOE, that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in 1998, as required by the contracts, and Alabama Power and Georgia Power have pursued and are pursuing legal remedies against the government for breach of contract. See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Fuel Disposal Costs" in Item 8 herein for additional information.

Natural Gas

Recent advances in natural gas drilling in shale producing regions of the United States have resulted in historically high supplies of natural gas and relatively low prices for natural gas. Procurement plans for natural gas supply and transportation to serve regulated utility customers are reviewed and approved by the state regulatory agencies in which Southern Company Gas operates. Southern Company Gas purchases natural gas supplies in the open market by contracting with producers and marketers and from its wholly-owned subsidiary, Sequent Energy Management, L.P., under asset management agreements in states where such agreements are approved by the applicable state regulatory agency. Southern Company Gas also contracts for transportation and storage services from interstate pipelines that are regulated by the FERC. When firm pipeline services are temporarily not needed, Southern Company Gas may release the services in the secondary market under FERC-approved capacity release provisions or utilize asset management arrangements, thereby reducing the net cost of natural gas charged to customers for most of the natural gas distribution utilities. Peak-use requirements are met through utilization of company-owned storage facilities, pipeline transportation capacity, purchased storage services, peaking facilities, and other supply sources, arranged by either transportation customers or Southern Company Gas.

Territory Served by the Southern Company System

Traditional Electric Operating Companies and Southern Power

The territory in which the traditional electric operating companies provide retail electric service comprises most of the states of Alabama and Georgia, together with the northwestern portion of Florida and southeastern Mississippi. In this territory there are non-affiliated electric distribution systems that obtain some or all of their power requirements either directly or indirectly from the traditional electric operating companies. As of December 31, 2017, the territory had an area of approximately 120,000 square miles and an estimated population of approximately 17 million. Southern Power sells electricity at market-based rates in the wholesale market, primarily to investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers.

Alabama Power is engaged, within the State of Alabama, in the generation, transmission, distribution, and purchase of electricity and the sale of electric service, at retail in approximately 400 cities and towns (including Anniston, Birmingham, Gadsden, Mobile, Montgomery, and Tuscaloosa), as well as in rural areas, and at wholesale to 14 municipally-owned electric distribution systems, 11 of which are served indirectly through sales to the Alabama Municipal Electric Authority, and two rural distributing cooperative associations. Alabama Power owns coal reserves near its Plant Gorgas and uses the output of coal from the reserves in its generating plants. Alabama Power also sells, and cooperates with dealers in promoting the sale of, electric appliances and products and markets and sells outdoor lighting services.

Georgia Power is engaged in the generation, transmission, distribution, and purchase of electricity and the sale of electric service within the State of Georgia, at retail in over 600 communities (including Athens, Atlanta, Augusta, Columbus, Macon, Rome, and Savannah), as well as in rural areas, and at wholesale to OPC, MEAG Power, Dalton, various EMCs, and non-affiliated utilities. Georgia Power also markets and sells outdoor lighting services.

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Gulf Power is engaged, within the northwestern portion of Florida, in the generation, transmission, distribution, and purchase of electricity and the sale of electric service, at retail in 71 communities (including Pensacola, Panama City, and Fort Walton Beach), as well as in rural areas, and at wholesale to a non-affiliated utility.

Mississippi Power is engaged in the generation, transmission, distribution, and purchase of electricity and the sale of electric service within 23 counties in southeastern Mississippi, at retail in 123 communities (including Biloxi, Gulfport, Hattiesburg, Laurel, Meridian, and Pascagoula), as well as in rural areas, and at wholesale to one municipality, six rural electric distribution cooperative associations, and one generating and transmitting cooperative.

For information relating to KWH sales by customer classification for the traditional electric operating companies, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS of each traditional electric operating company in Item 7 herein. For information relating to the number of retail customers served by customer classification for the traditional electric operating companies, see SELECTED FINANCIAL DATA of each traditional electric operating company in Item 6 herein. Also, for information relating to the sources of revenues for Southern Company, each traditional electric operating company, and Southern Power, reference is made to Item 7 herein.

The RUS has authority to make loans to cooperative associations or corporations to enable them to provide electric service to customers in rural sections of the country. As of December 31, 2017, there were approximately 62 electric cooperative distribution systems operating in the territory in which the traditional electric operating companies provide electric service at retail or wholesale.

One of these organizations, PowerSouth, is a generating and transmitting cooperative selling power to several distributing cooperatives, municipal systems, and other customers in south Alabama and northwest Florida. As of December 31, 2017, PowerSouth owned generating units with approximately 2,100 MWs of nameplate capacity, including an undivided 8.16% ownership interest in Alabama Power's Plant Miller Units 1 and 2. PowerSouth's facilities were financed with RUS loans secured by long-term contracts requiring distributing cooperatives to take their requirements from PowerSouth to the extent such energy is available. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for details of Alabama Power's joint-ownership with PowerSouth of a portion of Plant Miller. Alabama Power has a system supply agreement with PowerSouth to provide 200 MWs of capacity service through December 31, 2030 with an option to extend and renegotiate in the event Alabama Power builds new generation or contracts for new capacity.

Alabama Power and Gulf Power have entered into separate agreements with PowerSouth involving interconnection between their respective systems. The delivery of capacity and energy from PowerSouth to certain distributing cooperatives in the service territories of Alabama Power and Gulf Power is governed by the Southern Company/PowerSouth Network Transmission Service Agreement. The rates for this service to PowerSouth are on file with the FERC.

OPC is an EMC owned by its 38 retail electric distribution cooperatives, which provide retail electric service to customers in Georgia. OPC provides wholesale electric power to its members through its generation assets and power purchased from other suppliers.

Four electric cooperative associations, financed by the RUS, operate within Gulf Power's service territory. These cooperatives purchase their full requirements from PowerSouth and SEPA (a federal power marketing agency). A non-affiliated utility also operates within Gulf Power's service territory and purchases its full requirements from Gulf Power.

Mississippi Power has an interchange agreement with Cooperative Energy, a generating and transmitting cooperative, pursuant to which various services are provided.

As of December 31, 2017, there were approximately 72 municipally-owned electric distribution systems operating in the territory in which the traditional electric operating companies provide electric service at retail or wholesale.

As of December 31, 2017, 48 municipally-owned electric distribution systems and one county-owned system received their requirements through MEAG Power, which was established by a Georgia state statute in 1975. MEAG Power serves these requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and purchases from other resources. MEAG Power also has a pseudo scheduling and services agreement with Georgia Power. Dalton serves its requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and through purchases from Georgia Power and Southern Power through a service agreement. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for additional information.

Georgia Power has entered into substantially similar agreements with Georgia Transmission Corporation, MEAG Power, and Dalton providing for the establishment of an integrated transmission system to carry the power and energy of all parties. The agreements require an investment by each party in the integrated transmission system in proportion to its respective share of the aggregate system load. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for additional information.

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Southern Power assumed or entered into PPAs with some of the traditional electric operating companies, investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. See "The Southern Company System – Southern Power" above and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" of Southern Power in Item 7 herein for additional information concerning Southern Power's PPAs.

SCS, acting on behalf of the traditional electric operating companies, also has a contract with SEPA providing for the use of the traditional electric operating companies' facilities at government expense to deliver to certain cooperatives and municipalities, entitled by federal statute to preference in the purchase of power from SEPA, quantities of power equivalent to the amounts of power allocated to them by SEPA from certain U.S. government hydroelectric projects.

Southern Company Gas

Southern Company Gas is engaged in the distribution of natural gas in seven states through the natural gas distribution utilities. The natural gas distribution utilities construct, manage, and maintain intrastate natural gas pipelines and distribution facilities. Details of the natural gas distribution utilities at December 31, 2017 are as follows:



Utility	State	Number of customers	Approximate miles of pipe
		(in thousands)
Nicor Gas	Illinois	2,228	34,300
Atlanta Gas Light Company	Georgia	1,622	33,500
Virginia Natural Gas	Virginia	299	5,600
Elizabethtown Gas^(*)	New Jersey	292	3,200
Florida City Gas	Florida	109	3,700
Chattanooga Gas Company	Tennessee	66	1,600
Elkton Gas^(*)	Maryland	7	100
Total		4,623	82,000


(*)	For information relating to the pending asset sales of Elizabethtown Gas and Elkton Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Merger, Acquisition, and Disposition Activities" of Southern Company Gas in Item 7 herein and Note 11 to the financial statements of Southern Company Gas under "Proposed Sale of Elizabethtown Gas and Elkton Gas" in Item 8 herein.

For information relating to the sources of revenue for Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS and – FUTURE EARNINGS POTENTIAL of Southern Company Gas in Item 7 herein.

Competition

Electric

The electric utility industry in the U.S. is continuing to evolve as a result of regulatory and competitive factors. Among the early primary agents of change was the Energy Policy Act of 1992, which allowed IPPs to access a utility's transmission network in order to sell electricity to other utilities.

The competition for retail energy sales among competing suppliers of energy is influenced by various factors, including price, availability, technological advancements, service, and reliability. These factors are, in turn, affected by, among other influences, regulatory, political, and environmental considerations, taxation, and supply.

The retail service rights of all electric suppliers in the State of Georgia are regulated by the Territorial Electric Service Act of 1973. Pursuant to the provisions of this Act, all areas within existing municipal limits were assigned to the primary electric supplier therein. Areas outside of such municipal limits were either to be assigned or to be declared open for customer choice of supplier by action of the Georgia PSC pursuant to standards set forth in this Act. Consistent with such standards, the Georgia PSC has assigned substantially all of the land area in the state to a supplier. Notwithstanding such assignments, this Act provides that any new customer locating outside of 1973 municipal limits and having a connected load of at least 900 KWs may exercise a one-time choice for the life of the premises to receive electric service from the supplier of its choice.

Pursuant to the 1956 Utility Act, the Mississippi PSC issued "Grandfather Certificates" of public convenience and necessity to Mississippi Power and to six distribution rural cooperatives operating in southeastern Mississippi, then served in whole or in part by Mississippi Power, authorizing them to distribute electricity in certain specified geographically described areas of the state. The six cooperatives serve approximately 325,000 retail customers in a certificated area of approximately 10,300 square miles. In areas included in a "Grandfather Certificate," the utility holding such certificate may extend or maintain its electric

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system subject to certain regulatory approvals; extensions of facilities by such utility, or extensions of facilities into that area by other utilities, may not be made except upon a showing of, and a grant of a certificate of, public convenience and necessity. Areas included in such a certificate that are subsequently annexed to municipalities may continue to be served by the holder of the certificate, irrespective of whether it has a franchise in the annexing municipality. On the other hand, the holder of the municipal franchise may not extend service into such newly annexed area without authorization by the Mississippi PSC.

Generally, the traditional electric operating companies have experienced, and expect to continue to experience, competition in their respective retail service territories in varying degrees from the development and deployment of alternative energy sources such as self-generation (as described below) and distributed generation technologies, as well as other factors.

Southern Power competes with investor-owned utilities, IPPs, and others for wholesale energy sales across various U.S. utility markets. The needs of these markets are driven by the demands of end users and the generation available. Southern Power's success in wholesale energy sales is influenced by various factors including reliability and availability of Southern Power's plants, availability of transmission to serve the demand, price, and Southern Power's ability to contain costs.

As of December 31, 2017, Alabama Power had cogeneration contracts in effect with eight industrial customers. Under the terms of these contracts, Alabama Power purchases excess energy generated by such companies. During 2017, Alabama Power purchased approximately 98 million KWHs from such companies at a cost of $3 million.

As of December 31, 2017, Georgia Power had contracts in effect with 27 small power producers whereby Georgia Power purchases their excess generation. During 2017, Georgia Power purchased 1.6 billion KWHs from such companies at a cost of $114 million. Georgia Power also has PPAs for electricity with four cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity output. During 2017, Georgia Power purchased 26 million KWHs at a cost of $0.7 million from these facilities.

Also during 2017, Georgia Power purchased energy from three customer-owned generating facilities. These customers provide only energy to Georgia Power, make no capacity commitment, and are not dispatched by Georgia Power. During 2017, Georgia Power purchased a total of 317 million KWHs from the three customers at a cost of approximately $25 million.

As of December 31, 2017, Gulf Power had agreements in effect with various industrial, commercial, and qualifying facilities pursuant to which Gulf Power purchases "as available" energy from customer-owned generation. During 2017, Gulf Power purchased 277 million KWHs from such companies for approximately $7 million.

As of December 31, 2017, Mississippi Power had a cogeneration agreement in effect with one of its industrial customers. Under the terms of this contract, Mississippi Power purchases any excess generation. During 2017, Mississippi Power did not purchase any excess generation from this customer.

Natural Gas

Southern Company Gas' natural gas distribution utilities do not compete with other distributors of natural gas in their exclusive franchise territories but face competition from other energy products. Their principal competitors are electric utilities and fuel oil and propane providers serving the residential, commercial, and industrial markets in their service areas for customers who are considering switching to or from a natural gas appliance.

Competition for heating as well as general household and small commercial energy needs generally occurs at the initial installation phase when the customer or builder makes decisions as to which types of equipment to install. Customers generally use the chosen energy source for the life of the equipment.

Customer demand for natural gas could be affected by numerous factors, including:

changes in the availability or price of natural gas and other forms of energy;

general economic conditions;

energy conservation, including state-supported energy efficiency programs;

legislation and regulations;

the cost and capability to convert from natural gas to alternative energy products; and

technological changes resulting in displacement or replacement of natural gas appliances.

The natural gas-related programs generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities. In addition, Southern Company Gas partners with third-party entities to market the benefits of natural gas appliances.

The availability and affordability of natural gas have provided cost advantages and further opportunity for growth of the businesses.

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Seasonality

The demand for electric power and natural gas supply is affected by seasonal differences in the weather. In most of the areas the traditional electric operating companies serve, electric power sales peak during the summer with a smaller peak during the winter, while in most of the areas Southern Company Gas serves, natural gas demand peaks during the winter. As a result, the overall operating results of Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas in the future may fluctuate substantially on a seasonal basis. In addition, Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas have historically sold less power and natural gas when weather conditions are milder.

Regulation

State Commissions

The traditional electric operating companies and the natural gas distribution utilities are subject to the jurisdiction of their respective state PSCs or applicable state regulatory agencies. These regulatory bodies have broad powers of supervision and regulation over public utilities operating in the respective states, including their rates, service regulations, sales of securities (except for the Mississippi PSC), and, in the cases of the Georgia PSC and the Mississippi PSC, in part, retail service territories. See "Territory Served by the Southern Company System" and "Rate Matters" herein for additional information.

Federal Power Act

The traditional electric operating companies, Southern Power Company and certain of its generation subsidiaries, and SEGCO are all public utilities engaged in wholesale sales of energy in interstate commerce and, therefore, are subject to the rate, financial, and accounting jurisdiction of the FERC under the Federal Power Act. The FERC must approve certain financings and allows an "at cost standard" for services rendered by system service companies such as SCS and Southern Nuclear. The FERC is also authorized to establish regional reliability organizations which enforce reliability standards, address impediments to the construction of transmission, and prohibit manipulative energy trading practices.

Alabama Power and Georgia Power are also subject to the provisions of the Federal Power Act or the earlier Federal Water Power Act applicable to licensees with respect to their hydroelectric developments. As of December 31, 2017, among the hydroelectric projects subject to licensing by the FERC are 14 existing Alabama Power generating stations having an aggregate installed capacity of 1,670,000 KWs and 17 existing Georgia Power generating stations and one generating station partially owned by Georgia Power, with a combined aggregate installed capacity of 1,087,296 KWs.

In 2013, the FERC issued a new 30-year license to Alabama Power for Alabama Power's seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin). Alabama Power filed a petition requesting rehearing of the FERC order granting the relicense seeking revisions to several conditions of the license. Alabama Rivers Alliance, American Rivers, the Georgia Environmental Protection Division, and the Atlanta Regional Commission also filed petitions for rehearing of the FERC order. In April 2016, the FERC issued an order granting in part and denying in part Alabama Power's rehearing request. The order also denied all of the other rehearing requests. In May 2016, Alabama Rivers Alliance and American Rivers filed a second rehearing request and, in June 2016, also filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit for review of the license and the rehearing denial order. The FERC issued an order in September 2016 denying the second rehearing request, and American Rivers and Alabama Rivers Alliance subsequently filed an appeal of that order at the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit consolidated the two appeals into one proceeding.

In 2017, Alabama Power continued the process of developing an application to relicense the Harris Dam project on the Tallapoosa River, which is expected to be filed with the FERC by November 30, 2021. The current Harris Dam project license will expire on November 30, 2023.

In 2017, Georgia Power continued the process of developing an application to relicense the Wallace Dam project on the Oconee River. The current Wallace Dam project license will expire on June 1, 2020. Georgia Power's hydro electric licenses expiring in 2023 include the Lloyd Shoals project, the Riverview project, and the Langdale project. The FERC relicensing proceedings for these three projects are expected to begin in 2018.

Georgia Power and OPC also have a license, expiring in 2027, for the Rocky Mountain Plant, a pure pumped storage facility of 847,800 KW capacity. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for additional information.

Licenses for all projects, excluding those discussed above, expire in the years 2023-2066 in the case of Alabama Power's projects and in the years 2035-2044 in the case of Georgia Power's projects.

Upon or after the expiration of each license, the U.S. Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. In the event of takeover or relicensing to another,

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the original licensee is to be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property. The FERC may grant relicenses subject to certain requirements that could result in additional costs.

The ultimate outcome of these matters cannot be determined at this time.

Nuclear Regulation

Alabama Power, Georgia Power, and Southern Nuclear are subject to regulation by the NRC. The NRC is responsible for licensing and regulating nuclear facilities and materials and for conducting research in support of the licensing and regulatory process, as mandated by the Atomic Energy Act of 1954, as amended; the Energy Reorganization Act of 1974, as amended; and the Nuclear Nonproliferation Act of 1978, as amended; and in accordance with the National Environmental Policy Act of 1969, as amended, and other applicable statutes. These responsibilities also include protecting public health and safety, protecting the environment, protecting and safeguarding nuclear materials and nuclear power plants in the interest of national security, and assuring conformity with antitrust laws.

The NRC licenses for Georgia Power's Plant Hatch Units 1 and 2 expire in 2034 and 2038, respectively. The NRC licenses for Alabama Power's Plant Farley Units 1 and 2 expire in 2037 and 2041, respectively. The NRC licenses for Plant Vogtle Units 1 and 2 expire in 2047 and 2049, respectively.

In 2012, the NRC issued combined construction and operating licenses (COLs) for Plant Vogtle Units 3 and 4. Receipt of the COLs allowed full construction to begin. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 herein for additional information.

See Notes 1 and 9 to the financial statements of Southern Company, Alabama Power, and Georgia Power in Item 8 herein for information on nuclear decommissioning costs and nuclear insurance.

Environmental Laws and Regulations

The Southern Company system'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. Compliance with these existing environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions or through market-based contracts. There is no assurance, however, that all such costs will be recovered. For Southern Company Gas, substantially all of these costs are related to former manufactured gas plants sites, which are primarily recovered through existing ratemaking provisions. See Note 3 to the financial statements of Southern Company Gas under "Environmental Matters" in Item 8 herein for additional information.

Compliance with federal environmental laws and resulting regulations has been, and will continue to be, a significant focus for Southern Company, each traditional electric operating company, Southern Power, SEGCO, and Southern Company Gas. New or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company and each of the traditional electric operating companies in Item 7 herein for additional information about environmental issues, including, but not limited to, proposed and final regulations related to air quality, water quality, CCRs, and global climate issues. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 herein for additional information about environmental issues and global climate issues. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company Gas in Item 7 herein for additional information about environmental remediation liabilities.

The Southern Company system's ultimate environmental compliance strategy, including potential electric generating unit retirement and replacement decisions, and future environmental capital expenditures will depend on various factors, such as state-level adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. Environmental compliance spending over the next several years may differ materially from the amounts estimated. Such expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered on a timely basis through regulated rates for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Further, higher costs that are recovered through regulated rates

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could contribute to reduced demand for energy, which could negatively affect results of operations, cash flows, and 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 and natural gas. See "Construction Program" herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company, each of the traditional electric operating companies, Southern Power, and Southern Company Gas in Item 7 herein for additional information. The ultimate outcome of these matters cannot be determined at this time.

Rate Matters

Rate Structure and Cost Recovery Plans

Electric

The rates and service regulations of the traditional electric operating companies are uniform for each class of service throughout their respective retail service territories. Rates for residential electric service are generally of the block type based upon KWHs used and include minimum charges. Residential and other rates contain separate customer charges. Rates for commercial service are presently of the block type and, for large customers, the billing demand is generally used to determine capacity and minimum bill charges. These large customers' rates are generally based upon usage by the customer and include rates with special features to encourage off-peak usage. Additionally, Alabama Power, Gulf Power, and Mississippi Power are generally allowed by their respective state PSCs to negotiate the terms and cost of service to large customers. Such terms and cost of service, however, are subject to final state PSC approval.

The traditional electric operating companies recover certain costs through a variety of forward-looking, cost-based rate mechanisms. Fuel and net purchased energy costs are recovered through specific fuel cost recovery provisions. These fuel cost recovery provisions are adjusted to reflect increases or decreases in such costs as needed or on schedules as required by the respective PSCs. Approved compliance, storm damage, and certain other costs are recovered at Alabama Power, Gulf Power, and Mississippi Power through specific cost recovery mechanisms approved by their respective PSCs. Certain similar costs at Georgia Power are recovered through various base rate tariffs as approved by the Georgia PSC. Costs not recovered through specific cost recovery mechanisms are recovered at Alabama Power and Mississippi Power through annual, formulaic cost recovery proceedings and at Georgia Power and Gulf Power through periodic base rate proceedings.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters" of Southern Company and each of the traditional electric operating companies in Item 7 herein and Note 3 to the financial statements of Southern Company and each of the traditional electric operating companies under "Retail Regulatory Matters" in Item 8 herein for a discussion of rate matters and certain cost recovery mechanisms. Also, see Note 1 to the financial statements of Southern Company and each of the traditional electric operating companies in Item 8 herein for a discussion of recovery of fuel costs, storm damage costs, and compliance costs through rate mechanisms.

See "Integrated Resource Planning" herein for a discussion of Georgia PSC certification of new demand-side or supply-side resources for Georgia Power. In addition, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 herein for a discussion of the Georgia Nuclear Energy Financing Act and the Georgia PSC certification of Plant Vogtle Units 3 and 4, which have allowed Georgia Power to recover financing costs for construction of Plant Vogtle Units 3 and 4 during the construction period beginning in 2011.

See Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility" in Item 8 herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility – Rate Recovery" of Mississippi Power in Item 7 herein for information on cost recovery plans with respect to the Kemper County energy facility.

The traditional electric operating companies and Southern Power Company and certain of its generation subsidiaries are authorized by the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of each of the registrants in Item 7 herein for information on the traditional electric operating companies' and Southern Power Company's market-based rate authority and pending FERC proceedings relating to this authority.

Mississippi Power serves long-term contracts with rural electric cooperative associations and a municipality located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 19.3% of Mississippi Power's operating revenues in 2017 and are largely subject to rolling 10-

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year cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.

Natural Gas

Southern Company Gas' seven natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies with respect to rates charged to their customers, maintenance of accounting records, and various service and safety matters. Rates charged to these customers vary according to customer class (residential, commercial, or industrial) and rate jurisdiction. These agencies approve rates designed to provide each natural gas distribution utility the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt, and provide a reasonable return. Rate base generally consists of the original cost of the utility plant in service, working capital, and certain other assets, less accumulated depreciation on the utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.

With the exception of Atlanta Gas Light Company, which operates in a deregulated environment in which gas marketers rather than a traditional utility sell natural gas to end-use customers and earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are largely a function of weather conditions and price levels for natural gas.

The natural gas distribution utilities, excluding Atlanta Gas Light Company, are authorized to use natural gas cost recovery mechanisms that allow them to adjust their rates to reflect changes in the wholesale cost of natural gas and to ensure they recover all of the costs prudently incurred in purchasing natural gas for their customers. In addition to natural gas cost recovery mechanisms, the natural gas distribution utilities have 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 and energy efficiency plans.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Utility Regulation and Rate Design" of Southern Company Gas in Item 7 herein and Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 herein for a discussion of rate matters and certain cost recovery mechanisms.

Integrated Resource Planning

Each of the traditional electric operating companies continually evaluates its electric generating resources in order to ensure that it maintains a cost-effective and reliable mix of resources to meet the existing and future demand requirements of its customers. See "Environmental Laws and Regulations" above for a discussion of existing and potential environmental regulations that may impact the future generating resource needs of the traditional electric operating companies.

Certain of the traditional electric operating companies are required to file IRPs with their respective state PSC as discussed below.

Georgia Power

Triennially, Georgia Power must file an IRP with the Georgia PSC that specifies how it intends to meet the future electric service needs of its customers through a combination of demand-side and supply-side resources. The Georgia PSC, under state law, must certify any new demand-side or supply-side resources for Georgia Power to receive cost recovery. Once certified, the lesser of actual or certified construction costs and purchased power costs is recoverable through rates. Certified costs may be excluded from recovery only on the basis of fraud, concealment, failure to disclose a material fact, imprudence, or criminal misconduct.

See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Rate Plans" and " – Integrated Resource Plan" and "Nuclear Construction" and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans," "– Integrated Resource Plan," and "– Nuclear Construction" in Item 8 herein for additional information.

Gulf Power

Annually by April 1, Gulf Power must file a 10-year site plan with the Florida PSC containing Gulf Power's estimate of its power-generating needs in the period and the general location of its proposed power plant sites. The 10-year site plans submitted by the state's electric utilities are reviewed by the Florida PSC and subsequently classified as either "suitable" or "unsuitable." The Florida PSC then reports its findings along with any suggested revisions to the Florida Department of Environmental Protection for its consideration at any subsequent electrical power plant site certification proceedings. Under

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Florida law, any 10-year site plans submitted by an electric utility are considered tentative information for planning purposes only and may be amended at any time at the discretion of the utility with written notification to the Florida PSC.

Gulf Power's most recent 10-year site plan was classified by the Florida PSC as "suitable" in November 2017. The plan identifies environmental regulations and potential legislation or regulation that would impose mandatory restrictions on greenhouse gas emissions. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Air Quality," "– Environmental Laws and Regulations – Coal Combustion Residuals," and "– Global Climate Issues" of Gulf Power in Item 7 herein.

As a result of the cost to comply with environmental regulations imposed by the EPA, Gulf Power retired its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) in March 2016. In August 2016, the Florida PSC approved Gulf Power's request to reclassify the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date, totaling approximately $63 million, to a regulatory asset. Gulf Power began amortizing the investment balances over 15 years effective January 1, 2018 as determined in a rate case settlement agreement approved by the Florida PSC on April 4, 2017.

Mississippi Power

Mississippi Power's 2010 IRP indicated that, among other things, Mississippi Power planned to construct the Kemper County energy facility as an IGCC to meet its identified needs, to add environmental controls at Plant Daniel Units 1 and 2, to defer environmental controls at Plant Watson Units 4 and 5, and to continue operation of the combined cycle Plant Daniel Units 3 and 4. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Air Quality" and "– Global Climate Issues" of Mississippi Power in Item 7 herein.

On February 6, 2018, the Mississippi PSC approved a settlement agreement related to cost recovery for the Kemper County energy facility, pursuant to which Mississippi Power agreed to file a Reserve Margin Plan (RMP) by August 2018. The RMP will include many of the same aspects of a traditional IRP, but the RMP will also contain alternatives proposed by Mississippi Power to address its current capacity which is in excess of Mississippi Power's long-term targeted reserve margin. The ultimate outcome of this matter cannot be determined at this time.

For additional information regarding the Kemper County energy facility, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility" of Mississippi Power in Item 7 herein and Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility" in Item 8 herein.

Employee Relations

The Southern Company system had a total of 31,344 employees on its payroll at December 31, 2017.



	Employees at December 31, 2017
Alabama Power	6,613
Georgia Power	6,986
Gulf Power	1,288
Mississippi Power	1,242
PowerSecure	1,448
SCS	3,740
Southern Company Gas	5,318
Southern Nuclear	3,936
Southern Power	541
Other	232
Total	31,344

The traditional electric operating companies and the natural gas distribution utilities have separate agreements with local unions of the IBEW and the Utilities Workers Union of America generally covering wages, working conditions, and procedures for handling grievances and arbitration. These agreements apply with certain exceptions to operating, maintenance, and construction employees.

Alabama Power has agreements with the IBEW in effect through August 15, 2019. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.

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Georgia Power has an agreement with the IBEW covering wages and working conditions, which is in effect through June 30, 2021.

Gulf Power has an agreement with the IBEW covering wages and working conditions, which is in effect through April 15, 2019. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.

Mississippi Power has an agreement with the IBEW covering wages and working conditions, which is in effect through May 1, 2019. In 2015, Mississippi Power signed a separate agreement with the IBEW related solely to the Kemper County energy facility; that current agreement is in effect through March 15, 2021. In August 2017, Mississippi Power signed an agreement with the IBEW that added several job classifications and provided guidelines related to the reorganization at the Kemper County energy facility.

Southern Nuclear has a five-year agreement with the IBEW covering certain employees at Plants Hatch and Plant Vogtle Units 1 and 2, which is in effect through June 30, 2021. A five-year agreement between Southern Nuclear and the IBEW representing certain employees at Plant Farley is in effect through August 15, 2019. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.

The agreements also make the terms of the pension plans for the companies discussed above subject to collective bargaining with the unions at either a five-year or a 10-year cycle, depending upon union and company actions.

The natural gas distribution utilities have separate agreements with local unions of the IBEW and Utilities Workers Union of America covering wages, working conditions, and procedures for handling grievances and arbitration. Nicor Gas' agreement with the IBEW is effective through February 29, 2020. Virginia Natural Gas' agreement with the IBEW is effective through May 16, 2020. Elizabethtown Gas' agreement with the Utility Workers Union of America is effective through November 21, 2019. The agreements also make the terms of the Southern Company Gas pension plan subject to collective bargaining with the unions when significant changes to the benefit accruals are considered by Southern Company Gas.

Effective in December 2017, 538 employees transferred from SCS to Southern Power. Southern Power became obligated for related employee costs including pension, other postretirement benefits, and stock-based compensation and has recognized the respective balance sheet assets and liabilities, including accumulated other comprehensive income impacts, in its balance sheet at December 31, 2017. Prior to the transfer of employees, Southern Power's agreements with SCS provided for employee services rendered at amounts in compliance with FERC regulations.

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Item 1A. RISK FACTORS

In addition to the other information in this Form 10-K, includingMANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7 ofeach registrant, and other documents filed by Southern Company and/or itssubsidiaries with the SEC from time to time, the following factors should becarefully considered in evaluating Southern Company and its subsidiaries. Suchfactors could affect actual results and cause results to differ materially fromthose expressed in any forward-looking statements made by, or on behalf of, SouthernCompany and/or its subsidiaries.

UTILITY REGULATORY, LEGISLATIVE, AND LITIGATION RISKS

Southern Company and its subsidiaries are subject to substantial state and federal governmentalregulation. Compliance with current and future regulatory requirements andprocurement of necessary approvals, permits, and certificates may result insubstantial costs to Southern Company and its subsidiaries.

Southern Company and its subsidiaries, including the traditional electric operating companies, Southern Power, and Southern Company Gas, are subject to substantial regulation from federal, state, and local regulatory agencies. Southern Company and its subsidiaries are required to comply with numerous laws and regulations and to obtain numerous permits, approvals, and certificates from the governmental agencies that regulate various aspects of their businesses. Jointly-owned facilities may be subject to regulation by governmental agencies of more than one state and those state's governmental agencies may have different policies with respect to such jointly-owned facilities. The traditional electric operating companies and the natural gas distribution utilities seek to recover their costs (including a reasonable return on invested capital) through their retail rates, which must be approved by the applicable state PSC or other applicable state regulatory agency. A state PSC or other applicable state regulatory agency, in a future rate proceeding, may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required. Additionally, the rates charged to wholesale customers by the traditional electric operating companies and by Southern Power and the rates charged to natural gas transportation customers by Southern Company Gas' pipeline investments must be approved by the FERC. These wholesale rates could be affected by changes to Southern Power's and the traditional electric operating companies' ability to conduct business pursuant to FERC market-based rate authority. The FERC rules related to retaining the authority to sell electricity at market-based rates in the wholesale markets are important for the traditional electric operating companies and Southern Power if they are to remain competitive in the wholesale markets in which they operate.

The impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to Southern Company or any of its subsidiaries is uncertain. Changes in regulation or the imposition of additional regulations could influence the operating environment of Southern Company and its subsidiaries and may result in substantial costs or otherwise negatively affect their results of operations.

The Southern Company system's costs of compliance with environmental laws are significant. The costs of compliance with current and future environmental laws and the incurrence of environmental liabilities could negatively impact the net income, cash flows, and financial condition of the registrants.

The Southern Company system's operations are subject to extensive regulation by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and the protection of other natural resources. Compliance with these existing environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions or through market-based contracts. There is no assurance, however, that all such costs will be recovered. The registrants expect that these expenditures will continue to be significant in the future.

The EPA has adopted and is implementing regulations governing air and water quality, including the emission of nitrogen oxide, sulfur dioxide, fine particulate matter, ozone, mercury, and other air pollutants under the Clean Air Act and regulations governing cooling water intake structures and effluent guidelines for steam electric generating plants under the Clean Water Act. The EPA also is reconsidering regulations governing the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments at power generation plants.

Additionally, environmental laws and regulations covering the handling and disposal of waste and release of hazardous substances could require the Southern Company system to incur substantial costs to clean up affected sites, including certain current and former operating sites, and locations affected by historical operations or subject to contractual obligations.

Existing environmental laws and regulations may be revised or new laws and regulations related to air, water, land, and the protection of other natural resources may be adopted or become applicable to the traditional electric operating companies, Southern Power, and/or Southern Company Gas.

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Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂and other emissions, CCR, releases of regulated substances, and alleged exposure to regulated substances, and/or requests for injunctive relief in connection with such matters.

The Southern Company system's ultimate environmental compliance strategy, including potential electric generating unit retirement and replacement decisions, and future environmental capital expenditures will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. Environmental compliance spending over the next several years may differ materially from the amounts estimated. Such expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered on a timely basis through regulated rates for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for energy, which could negatively affect results of operations, cash flows, and 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 or natural gas.

Compliance with any new or revised environmental laws or regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. The ultimate impact will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which may affect their demand for electricity and natural gas.

The Southern Company system may be exposed to regulatory and financial risks related to the impact of greenhouse gas (GHG) legislation and regulation.

In 2015, the EPA published final rules limiting CO₂ emissions from new, modified, and reconstructed fossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO₂emission performance standards for existing units (known as the Clean Power Plan or CPP). In February 2016, the U.S. Supreme Court granted a stay of the CPP, which will remain in effect through the resolution of the litigation in the U.S. Court of Appeals for the District of Columbia challenging the legality of the CPP and any review by the U.S. Supreme Court. On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including review of the CPP and other CO₂ emissions rules. On October 10, 2017, the EPA published a proposed rule to repeal the CPP and, on December 28, 2017, published an advanced notice of proposed rulemaking regarding a CPP replacement rule.

In 2015, parties to the United Nations Framework Convention on Climate Change, including the United States, adopted the Paris Agreement, which established a non-binding universal framework for addressing GHG emissions based on nationally determined contributions. On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate impact of this agreement or any renegotiated agreement depends on its implementation by participating countries.

Costs associated with these actions could be significant to the utility industry and the Southern Company system. However, the ultimate impact of these environmental laws and regulations will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.

Because natural gas is a fossil fuel with lower carbon content relative to other fossil fuels, future GHG constraints may create additional demand for natural gas, both for production of electricity and direct use in homes and businesses. The impact is already being seen in the power production sector due to both environmental regulations and low natural gas costs. Future GHG constraints focused on minimizing emissions from natural gas, albeit lower than other fossil fuels, could likewise result in increased costs to the Southern Company system and affect the demand for natural gas as well as the prices charged to customers and the competitive position of natural gas.

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The net income of Southern Company, the traditional electric operating companies, and Southern Power could be negatively impacted by changes in regulations related to transmission planning processes and competition in the wholesale electric markets.

The traditional electric operating companies currently own and operate transmission facilities as part of a vertically integrated utility. A small percentage of transmission revenues are collected through the wholesale electric tariff but the majority of transmission revenues are collected through retail rates. FERC rules pertaining to regional transmission planning and cost allocation present challenges to transmission planning and the wholesale market structure in the Southeast. The key impacts of these rules include:

possible disruption of the integrated resource planning processes within the states in the Southern Company system's service territory;

delays and additional processes for developing transmission plans; and

possible impacts on state jurisdiction of approving, certifying, and pricing new transmission facilities.

The FERC rules related to transmission are intended to spur the development of new transmission infrastructure to promote and encourage the integration of renewable sources of supply as well as facilitate competition in the wholesale market by providing more choices to wholesale power customers. Technology changes in the power and fuel industries continue to create significant impacts to wholesale transaction cost structures. The impact of these and other such developments and the effect of changes in levels of wholesale supply and demand are uncertain. The financial condition, net income, and cash flows of Southern Company, the traditional electric operating companies, and Southern Power could be adversely affected by these and other changes.

The traditional electric operating companies and Southern Power could be subject to higher costs as a result of implementing and maintaining compliance with the North American Electric Reliability Corporation mandatory reliability standards along with possible associated penalties for non-compliance.

Owners and operators of bulk power systems, including the traditional electric operating companies, are subject to mandatory reliability standards enacted by the North American Electric Reliability Corporation and enforced by the FERC. Compliance with or changes in the mandatory reliability standards may subject the traditional electric operating companies and Southern Power to higher operating costs and/or increased capital expenditures. If any traditional electric operating company or Southern Power is found to be in noncompliance with these standards, such traditional electric operating company or Southern Power could be subject to sanctions, including substantial monetary penalties.

Southern Company and its subsidiaries are continuing to review the Tax Reform Legislation, which has and could have a further material impact on the results of operations, financial condition, and cash flows of the registrants.

On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation significantly changes the U.S. Internal Revenue Code by, among other things, reducing the federal corporate income tax rate to 21% and repealing the corporate alternative minimum tax. As a result of the tax rate reduction, Southern Company recorded net, non-cash federal income tax benefits of $264 million in the fourth quarter 2017, comprised primarily of a $743 million tax benefit resulting from reductions in deferred tax liabilities at Southern Power, partially offset by tax expenses of $372 million and $93 million resulting from reductions in deferred tax assets at Mississippi Power and Southern Company Gas, respectively.

The tax rate reduction also resulted in a $6.9 billion increase in regulatory liabilities and a $0.4 billion decrease in regulatory assets across the traditional electric operating companies and the natural gas distribution utilities. The regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the relevant state regulatory bodies.

For businesses other than regulated utility businesses, the Tax Reform Legislation allows 100% bonus depreciation of qualified property through 2022, which phases down through 2027, and limits interest expense deductions. Regulated utility businesses, including the majority of the operations of the traditional electric operating companies and the natural gas distribution companies, can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. The Tax Reform Legislation retains normalization provisions for public utility property and existing renewable energy incentives. However, the tax rate reduction delays the utilization of renewable tax credit carryforwards as described in Note 5 to the financial statements of Southern Company, Alabama Power, Georgia Power, and Southern Power under "Federal Tax Reform Legislation" in Item 8 herein.

The Tax Reform Legislation also includes provisions that limit the utilization of future net operating losses and limit the deductibility of certain executive compensation and other expenses. Further, while it is unclear how the credit rating agencies, the FERC, and relevant state regulatory bodies may respond to the Tax Reform Legislation, certain financial metrics, such as funds from operations to debt percentage, used by the credit rating agencies to assess the registrants, Southern Company Gas Capital, and Nicor Gas may be negatively impacted.

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The Tax Reform Legislation is unclear in certain respects and will require interpretations, guidance, and implementing regulations by the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and relevant state regulatory bodies. Southern Company and its subsidiaries are continuing to review the Tax Reform Legislation and are assessing whether any potential actions are available to mitigate adverse impacts of the legislation. Southern Company and its subsidiaries may identify additional impacts as they further assess the Tax Reform Legislation and as the IRS issues interpretations and implements regulations. Southern Company will continue to monitor the actions of state legislatures and state taxing authorities to see how the states may adopt and implement the Tax Reform Legislation. While the ultimate impact of the Tax Reform Legislation, future interpretations and implementation of regulations by the IRS and state tax authorities, and any mitigating actions Southern Company and its subsidiaries may take cannot be determined at this time, the Tax Reform Legislation had and could have a further material impact on the results of operations, financial condition and cash flows of the registrants.

OPERATIONAL RISKS

The financial performance of Southern Company and its subsidiaries may be adverselyaffected if the subsidiaries are unable to successfully operate their facilities or perform certain corporate functions.

The financial performance of Southern Company and its subsidiaries depends on the successful operation of the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions. There are many risks that could affect these operations and performance of corporate functions, including:

operator error or failure of equipment or processes;

accidents or explosions;

operating limitations that may be imposed by environmental or other regulatory requirements;

labor disputes;

terrorist attacks (physical and/or cyber);

fuel or material supply interruptions;

transmission disruption or capacity constraints, including with respect to the Southern Company system's and third parties' transmission, storage, and transportation facilities;

compliance with mandatory reliability standards, including mandatory cyber security standards;

implementation of new technologies;

information technology system failure;

cyber intrusion;

an environmental event, such as a spill or release; and

catastrophic events such as fires, earthquakes, floods, droughts, hurricanes, tornadoes, and storms, pandemic health events such as influenzas, or other similar occurrences.

A decrease or elimination of revenues from the electric generation, transmission, or distribution facilities or natural gas distribution or storage facilities or an increase in the cost of operating the facilities would reduce the net income and cash flows and could adversely impact the financial condition of the affected traditional electric operating company, Southern Power, or Southern Company Gas and of Southern Company.

Operation of nuclear facilities involves inherent risks, including environmental,safety, health, regulatory, natural disasters, terrorism, and financial risks, that could result in fines or theclosure of the nuclear units owned by Alabama Power or Georgia Powerand which may present potential exposures in excess of insurance coverage.

Alabama Power owns, and contracts for the operation of, two nuclear units and Georgia Power holds undivided interests in, and contracts for the operation of, four existing nuclear units. The six existing units are operated by Southern Nuclear and represent approximately 3,680 MWs, or 8% of the Southern Company system's electric generation capacity as of December 31, 2017. In addition, these units generated approximately 25% of the total KWHs generated by each of Alabama Power and Georgia Power in the year ended December 31, 2017. In addition, Southern Nuclear, on behalf of Georgia Power and the other Vogtle Owners, is managing the construction of Plant Vogtle Units 3 and 4. Due solely to the increase in nuclear generating capacity, the below risks are expected to increase incrementally once Plant Vogtle Units 3 and 4 are operational. Nuclear facilities are subject to environmental, safety, health, operational, and financial risks such as:

the potential harmful effects on the environment and human health and safety resulting from a release of radioactive materials in connection with the operation of nuclear facilities and the storage, handling, and disposal of radioactive material, including spent nuclear fuel;

uncertainties with respect to the ability to dispose of spent nuclear fuel and the need for longer term on-site storage;

uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of licensed lives and the ability to maintain and anticipate adequate capital reserves for decommissioning;

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limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with the nuclear operations of Alabama Power and Georgia Power or those of other commercial nuclear facility owners in the U.S.;

potential liabilities arising out of the operation of these facilities;

significant capital expenditures relating to maintenance, operation, security, and repair of these facilities, including repairs and upgrades required by the NRC;

the threat of a possible terrorist attack, including a potential cyber security attack; and

the potential impact of an accident or natural disaster.

It is possible that damages, decommissioning, or other costs could exceed the amount of decommissioning trusts or external insurance coverage, including statutorily required nuclear incident insurance.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down any unit, depending upon its assessment of the severity of the situation, until compliance is achieved. NRC orders or regulations related to increased security measures and any future safety requirements promulgated by the NRC could require Alabama Power and Georgia Power to make substantial operating and capital expenditures at their nuclear plants. In addition, if a serious nuclear incident were to occur, it could result in substantial costs to Alabama Power or Georgia Power and Southern Company. A major incident at a nuclear facility anywhere in the world could cause the NRC to delay or prohibit construction of new nuclear units or require additional safety measures at new and existing units. Moreover, a major incident at any nuclear facility in the U.S., including facilities owned and operated by third parties, could require Alabama Power and Georgia Power to make material contributory payments.

In addition, potential terrorist threats could result in increased nuclear licensing or compliance costs that are difficult to predict.

Transporting and storing natural gas involves risks that may result in accidents and other operating risks and costs.

Southern Company Gas' natural gas distribution and storage activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, explosions, and mechanical problems, which could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, and impairment of its operations. The location of pipelines and storage facilities near populated areas could increase the level of damage resulting from these risks. Additionally, these pipeline and storage facilities are subject to various state and other regulatory requirements. Failure to comply with these regulatory requirements could result in substantial monetary penalties or potential early retirement of storage facilities, which could trigger an associated impairment. The occurrence of any of these events not fully covered by insurance or otherwise could adversely affect Southern Company Gas' and Southern Company's financial condition and results of operations.

Physical attacks, both threatened and actual, could impact the ability of the traditional electric operating companies, Southern Power, and Southern Company Gas to operate and could adversely affect financial results and liquidity.

The traditional electric operating companies, Southern Power, and Southern Company Gas face the risk of physical attacks, both threatened and actual, against their respective generation and storage facilities and the transmission and distribution infrastructure used to transport energy, which could negatively impact their ability to generate, transport, and deliver power, or otherwise operate their respective facilities, or, with respect to Southern Company Gas, its ability to distribute or store natural gas, or otherwise operate its facilities, in the most efficient manner or at all. In addition, physical attacks against key suppliers or service providers could have a similar effect on Southern Company and its subsidiaries.

Despite the implementation of robust security measures, all assets are potentially vulnerable to disability, failures, or unauthorized access due to human error, natural disasters, technological failure, or internal or external physical attacks. If assets were to fail, be physically damaged, or be breached and were not recovered in a timely way, the traditional electric operating companies, Southern Power, or Southern Company Gas, as applicable, may be unable to fulfill critical business functions. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or physical security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result.

These events could harm the reputation of and negatively affect the financial results of the registrants through lost revenues and costs to repair damage, if such costs cannot be recovered.

An information security incident, including a cybersecurity breach, or the failure of one or more key information technology systems, networks, or processes could impact the ability of the registrants to operate and could adversely affect financial results and liquidity.

Information security risks have generally increased in recent years as a result of the proliferation of new technology and increased sophistication and frequency of cyber attacks and data security breaches. The traditional electric operating

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companies, Southern Power, and Southern Company Gas operate in highly regulated industries that require the continued operation of sophisticated information technology systems and network infrastructure, which are part of interconnected distribution systems. Because of the critical nature of the infrastructure, increased connectivity to the internet, and technology systems' inherent vulnerability to disability or failures due to hacking, viruses, acts of war or terrorism, or other types of data security breaches, Southern Company and its subsidiaries face a heightened risk of cyberattack. Parties that wish to disrupt the U.S. bulk power system or Southern Company system operations could view these computer systems, software, or networks as targets. The registrants and their third-party vendors have been subject, and will likely continue to be subject, to attempts to gain unauthorized access to their information technology systems and confidential data or to attempts to disrupt utility operations. As a result, Southern Company and its subsidiaries face on-going threats to their assets, including assets deemed critical infrastructure, where databases and systems have been, and will likely continue to be, subject to advanced computer viruses or other malicious codes, unauthorized access attempts, phishing, and other cyber attacks. While there has been no material impact on business or operations from these attacks, the registrants cannot guarantee that security efforts will prevent breaches, operational incidents, or other breakdowns of information technology systems and network infrastructure.

In addition, in the ordinary course of business, Southern Company and its subsidiaries collect and retain sensitive information, including personally identifiable information about customers, employees, and stockholders, and other confidential information. In some cases, administration of certain functions may be outsourced to third party service providers that could also be targets of cyber attacks. Generally, Southern Company and its subsidiaries enter certain contractual security guarantees and assurances with these third parties to help ensure the security and safety of this information.

Despite the implementation of robust security measures, all assets are potentially vulnerable to disability, failures, or unauthorized access due to human error, natural disasters, technological failure, or internal or external cyber attacks. If assets were to fail or be breached and were not recovered in a timely way, the affected registrant may be unable to fulfill critical business functions, and sensitive and other data could be compromised. Any cyber breach or theft, damage, or improper disclosure of sensitive electronic data may also subject the affected registrant to penalties and claims from regulators or other third parties. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result.

These events could negatively affect the financial results of the registrants through lost revenues, costs to recover and repair damage, and costs associated with governmental actions in response to such attacks, litigation, and reputational damage if such costs cannot be recovered through insurance or otherwise.

The Southern Company system may not be able to obtainadequate natural gas and other fuel supplies required to operate the traditional electric operating companies' and Southern Power's electric generating plants or serve Southern Company Gas' natural gas customers.

The traditional electric operating companies and Southern Power purchase fuel, including coal, natural gas, uranium, fuel oil, and biomass, as applicable, from a number of suppliers. Disruption in the delivery of fuel, including disruptions as a result of, among other things, transportation delays, weather, labor relations, force majeure events, or environmental regulations affecting any of these fuel suppliers, could limit the ability of the traditional electric operating companies and Southern Power to operate certain facilities, which could result in higher fuel and operating costs and potentially reduce the net income of the affected traditional electric operating company or Southern Power and Southern Company.

Southern Company Gas' primary business is the distribution and sale of natural gas through its regulated and unregulated subsidiaries. Natural gas supplies can be subject to disruption in the event production or distribution is curtailed, such as in the event of a hurricane or a pipeline failure. Southern Company Gas also relies on natural gas pipelines and other storage and transportation facilities owned and operated by third parties to deliver natural gas to wholesale markets and to Southern Company Gas' distribution systems. The availability of shale gas and potential regulations affecting its accessibility may have a material impact on the supply and cost of natural gas. Disruption in natural gas supplies could limit the ability to fulfill these contractual obligations.

The traditional electric operating companies and Southern Power have become more dependent on natural gas for a portion of their electric generating capacity. In many instances, the cost of purchased power ~~expense was $645 million,~~for the traditional electric operating companies and Southern Power is influenced by natural gas prices. Historically, natural gas prices have been more volatile than prices of other fuels. In recent years, domestic natural gas prices have been depressed by robust supplies, including production from shale gas. These market conditions, together with additional regulation of coal-fired generating units, have increased the traditional electric operating companies' reliance on natural gas-fired generating units.

The traditional electric operating companies are also dependent on coal for a ~~decrease~~portion of ~~$27 million,~~their electric generating capacity. The traditional electric operating companies depend on coal supply contracts, and the counterparties to these agreements may not fulfill their obligations to supply coal to the traditional electric operating companies. The suppliers may experience financial or ~~4.0%~~

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technical problems that inhibit their ability to fulfill their obligations. In addition, the suppliers may not be required to supply coal under certain circumstances, such as in the event of a natural disaster. If the traditional electric operating companies are unable to obtain their coal requirements under these contracts, they may be required to purchase their coal requirements at higher prices, which may not be recoverable through rates.

The revenues of Southern Company, the traditional electric operating companies, and SouthernPower depend inpart on sales under PPAs. The failure of a counterparty to one of these PPAs toperform its obligations, the failure of the traditional electric operating companies or Southern Power to satisfy minimum requirements under the PPAs, or the failure to renew the PPAs or successfully remarket the related generating capacity could have a negativeimpact on the net income and cash flows of the affected traditional electric operating companyor Southern Power and of Southern Company.

Most of Southern Power's generating capacity has been sold to purchasers under PPAs. Southern Power's top three customers, Georgia Power, Duke Energy Corporation, and Morgan Stanley Capital Group accounted for 11.3%, 6.7%, and 4.5%, respectively, of Southern Power's total revenues for the year ended December 31, 2017. In addition, the traditional electric operating companies enter into PPAs with non-affiliated parties. Revenues are dependent on the continued performance by the purchasers of their obligations under these PPAs. The failure of one of the purchasers to perform its obligations could have a negative impact on the net income and cash flows of the affected traditional electric operating company or Southern Power and of Southern Company. Although the credit evaluations undertaken and contractual protections implemented by Southern Power and the traditional electric operating companies take into account the possibility of default by a purchaser, actual exposure to a default by a purchaser may be greater than predicted or specified in the applicable contract.

Additionally, neither Southern Power nor any traditional electric operating company can predict whether the PPAs will be renewed at the end of their respective terms or on what terms any renewals may be made. The failure of the traditional electric operating companies or Southern Power to satisfy minimum operational or availability requirements under these PPAs could result in payment of damages or termination of the PPAs.

The asset management arrangements between Southern Company Gas' wholesale gas services and its customers, including the natural gas distribution utilities, may not be renewed or may be renewed at lower levels, which could have a significant impact on Southern Company Gas' financial results.

Southern Company Gas' wholesale gas services currently manages the storage and transportation assets of the natural gas distribution utilities except Nicor Gas. The profits earned from the management of these affiliate assets are shared with the respective affiliate's customers (and for Atlanta Gas Light Company with the Georgia PSC's Universal Service Fund), except for Chattanooga Gas Company and Elkton Gas where wholesale gas services are provided under annual fixed-fee agreements. These asset management agreements are subject to regulatory approval and such agreements may not be renewed or may be renewed with less favorable terms.

Southern Company Gas' wholesale gas services also has asset management agreements with certain non-affiliated customers and its financial results could be significantly impacted if these agreements are not renewed or are amended or renewed with less favorable terms. Sustained low natural gas prices could reduce the demand for these types of asset management arrangements.

Increased competition could negatively impact Southern Company's and its subsidiaries' revenues, results of operations, and financial condition.

The Southern Company system faces increasing competition from other companies that supply energy or generation and storage technologies. Changes in technology may make the Southern Company system's electric generating facilities owned by the traditional electric operating companies and Southern Power less competitive. Southern Company Gas' business is dependent on natural gas prices remaining competitive as compared to other forms of energy. Southern Company Gas also faces competition in its unregulated markets.

A key element of the business models of the traditional electric operating companies and Southern Power is that generating power at central station power plants achieves economies of scale and produces power at a competitive cost. There are distributed generation and storage technologies that produce and store power, including fuel cells, microturbines, wind turbines, solar cells, and batteries. Advances in technology or changes in laws or regulations could reduce the cost of these or other alternative methods of producing power to a level that is competitive with that of most central station power electric production or result in smaller-scale, more fuel efficient, and/or more cost effective distributed generation that allows for increased self-generation by customers. Broader use of distributed generation by retail energy customers may also result from customers' changing perceptions of the merits of utilizing existing generation technology or tax or other economic incentives. Additionally, a state PSC or legislature may modify certain aspects of the traditional electric operating companies' business as a result of these advances in technology.

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It is also possible that rapid advances in central station power generation technology could reduce the value of the current electric generating facilities owned by the traditional electric operating companies and Southern Power. Changes in technology could also alter the channels through which electric customers buy or utilize power, which could reduce the revenues or increase the expenses of Southern Company, the traditional electric operating companies, or Southern Power.

Southern Company Gas' gas marketing services is affected by competition from other energy marketers providing similar services in Southern Company Gas' service territories, most notably in Illinois and Georgia. Southern Company Gas' wholesale gas services competes for sales with national and regional full-service energy providers, energy merchants and producers, and pipelines based on the ability to aggregate competitively-priced commodities with transportation and storage capacity. Southern Company Gas competes with natural gas facilities in the Gulf Coast region of the U.S., as the majority of the existing and proposed high deliverability salt-dome natural gas storage facilities in North America are located in the Gulf Coast region.

If new technologies become cost competitive and achieve sufficient scale, the market share of the traditional electric operating companies, Southern Power, and Southern Company Gas could be eroded, and the value of their respective electric generating facilities or natural gas distribution and storage facilities could be reduced. Additionally, Southern Company Gas' market share could be reduced if Southern Company Gas cannot remain price competitive in its unregulated markets. If state PSCs or other applicable state regulatory agencies fail to adjust rates to reflect the impact of any changes in loads, increasing self-generation, and the growth of distributed generation, the financial condition, results of operations, and cash flows of Southern Company and the affected traditional electric operating company or Southern Company Gas could be materially adversely affected.

Failure to attract and retain an appropriately qualified workforce could negatively impact Southern Company's and its subsidiaries' results of operations.

Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, or unavailability of contract resources may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including with the workforce needs associated with major construction projects and ongoing operations. The Southern Company system's costs, including costs for contractors to replace employees, productivity costs, and safety costs, may rise. Failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect Southern Company and its subsidiaries' ability to manage and operate their businesses. If Southern Company and its subsidiaries are unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.

CONSTRUCTION RISKS

The registrants may incuradditional costs or delays in the construction of new plants or other facilities and may not be able to recover their investments. Also, existing facilities ofthe traditional electric operating companies, Southern Power, and Southern Company Gas requireongoing capital expenditures, including those to meet environmental standards.

General

The businesses of the registrants require substantial capital expenditures for investments in new facilities and, for the traditional electric operating companies, capital improvements to transmission, distribution, and generation facilities, and, for Southern Company Gas, capital improvements to natural gas distribution and storage facilities, including those to meet environmental standards. Certain of the traditional electric operating companies and Southern Power are in the process of constructing new generating facilities and adding environmental controls equipment at existing generating facilities. Southern Company Gas is replacing certain pipelines in its natural gas distribution system and is involved in two new gas pipeline construction projects. The Southern Company system intends to continue its strategy of developing and constructing other new facilities, expanding or updating existing facilities, and adding environmental control equipment. These types of projects are long term in nature and in some cases include the development and construction of facilities with designs that have not been finalized or previously constructed. The completion of these types of projects without delays or significant cost overruns is subject to substantial risks, including:

shortages and inconsistent quality of equipment, materials, and labor;

changes in labor costs and productivity;

work stoppages;

contractor or supplier delay or non-performance under construction, operating, or other agreements or non-performance by other major participants in construction projects;

delays in or failure to receive necessary permits, approvals, tax credits, and other regulatory authorizations;

delays associated with start-up activities, including major equipment failure and system integration, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC or other applicable state regulatory agency);

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operational readiness, including specialized operator training and required site safety programs;

impacts of new and existing laws and regulations, including environmental laws and regulations;

the outcome of legal challenges to projects, including legal challenges to regulatory approvals;

failure to construct in accordance with permitting and licensing requirements;

failure to satisfy any environmental performance standards and the requirements of tax credits and other incentives;

continued public and policymaker support for such projects;

adverse weather conditions or natural disasters;

other unforeseen engineering or design problems;

changes in project design or scope;

environmental and geological conditions;

delays or increased costs to interconnect facilities to transmission grids; and

unanticipated cost increases, including materials and labor, and increased financing costs as a result of changes in market interest rates or as a result of construction schedule delays.

If a traditional electric operating company, Southern Power, or Southern Company Gas is unable to complete the development or construction of a project or decides to delay or cancel construction of a project, it may not be able to recover its investment in that project and may incur substantial cancellation payments under equipment purchase orders or construction contracts. Additionally, each Southern Company Gas pipeline construction project involves separate joint venture participants, Southern Power participates in partnership agreements with respect to renewable energy projects, and Georgia Power jointly owns Plant Vogtle Units 3 and 4 with other co-owners. Any failure by a partner or co-owner to perform its obligations under the applicable agreements could have a material negative impact on the applicable project under construction. In addition, partnership and joint ownership agreements may provide partners or co-owners with certain decision-making authority in connection with projects under construction.

Even if a construction project (including a joint venture construction project) is completed, the total costs may be higher than estimated and may not be recoverable through regulated rates, if applicable. In addition, construction delays and contractor performance shortfalls can result in the loss of revenues and may, in turn, adversely affect the net income and financial position of the affected registrant.

Construction delays could result in the loss of otherwise available investment tax credits, PTCs, and other tax incentives. Furthermore, if construction projects are not completed according to specification, a traditional electric operating company, Southern Power, or Southern Company Gas and Southern Company may incur liabilities and suffer reduced plant efficiency, higher operating costs, and reduced net income.

Once facilities become operational, ongoing capital expenditures are required to maintain reliable levels of operation. Significant portions of the traditional electric operating companies' existing facilities were constructed many years ago. Older equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements, or to provide safe and reliable operations.

The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4.

Plant Vogtle Units 3 and 4 construction and rate recovery

In 2009, the Georgia PSC certified construction of 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 a substantially fixed price engineering, procurement, and construction agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. On March 29, 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 Vogtle Owners, entered into an agreement with the EPC Contractor to allow construction to continue (Interim Assessment Agreement). The Interim Assessment Agreement expired on July 27, 2017 upon the effectiveness of a services agreement between the Vogtle Owners and the EPC Contractor for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear (Vogtle Services Agreement). In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, Georgia Power filed its seventeenth Vogtle Construction Monitoring (VCM) report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel Power Corporation (Bechtel) serving as the primary construction contractor. Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The construction completion agreement between Georgia Power, for itself and as agent for the other Vogtle Owners, and Bechtel (Bechtel Agreement) is a cost reimbursable plus

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fee arrangement, whereby Bechtel will be 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.

On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, 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 (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power 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 because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.

On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's recommendation to continue construction and 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 December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the original engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4 (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 $5.680 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 $5.680 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 the Customer Refunds, each as defined below) is 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 return on equity (ROE) used to calculate the Nuclear Construction Cost Recovery (NCCR) tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 Alternative Rate Plan) 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 allowance for funds used during construction 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 settlement agreement approved by the Georgia PSC on December 20, 2016. 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. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Georgia PSC reserve the right to reconsider the decision to continue construction.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. Georgia Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.

Georgia Power expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. Georgia Power's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under a settlement agreement regarding Toshiba's guarantee of certain obligations of the EPC Contractor (Guarantee Settlement Agreement) and certain refunds to customers ordered by the Georgia PSC (Customer Refunds)). Georgia Power's construction work in progress balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.

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As construction continues, challenges with management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new technology and have not yet operated in the global nuclear industry at this scale), or other issues could arise and change the projected schedule and estimated cost.

The ultimate outcome of these matters cannot be determined at this time.

See Note 3 to the financial statements of Southern Company under "Nuclear Construction" and of Georgia Power under "Retail Regulatory Matters - Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

Southern Company Gas' significant investments in pipelines and pipeline development projects involve financial and execution risks.

Southern Company Gas has made significant investments in existing pipelines and pipeline development projects. Many of the existing pipelines are, and when completed many of the pipeline development projects will be, operated by third parties. If one of these agents fails to perform in a proper manner, the value of the investment could decline and Southern Company Gas could lose part or all of the investment. In addition, from time to time, Southern Company Gas may be required to contribute additional capital to a pipeline joint venture or guarantee the obligations of such joint venture.

With respect to certain pipeline development projects, Southern Company Gas will rely on its joint venture partners for construction management and will not exercise direct control over the process. All of the pipeline development projects are dependent on contractors for the successful and timely completion of the projects. Further, the development of pipeline projects involves numerous regulatory, environmental, construction, safety, political, and legal uncertainties and may require the expenditure of significant amounts of capital. These projects may not be completed on schedule, at the budgeted cost, or at all. There may be cost overruns and construction difficulties that cause Southern Company Gas' capital expenditures to exceed its initial expectations. Moreover, Southern Company Gas' revenues will not increase immediately upon the expenditure of funds on a pipeline project. Pipeline construction occurs over an extended period of time and Southern Company Gas will not receive material increases in revenues until the project is placed in service.

The occurrence of any of the foregoing events could adversely affect the results of operations, cash flows, and financial condition of Southern Company Gas and Southern Company.

FINANCIAL, ECONOMIC, AND MARKET RISKS

The electric generation and energy marketing operations of the traditional electric operating companies and Southern Power and the natural gas operations of Southern Company Gas are subject to risks, many of which are beyondtheir control, including changes in energy prices and fuel costs, which may reduce revenues and increase costs.

The generation, energy marketing, and natural gas operations of the Southern Company system are subject to changes in energy prices and fuel costs, which could increase the cost of producing power, decrease the amount received from the sale of energy, and/or make electric generating facilities less competitive. The market prices for these commodities may fluctuate significantly over relatively short periods of time. Among the factors that could influence energy prices and fuel costs are:

prevailing market prices for coal, natural gas, uranium, fuel oil, biomass, and other fuels, as applicable, used in the generation facilities of the traditional electric operating companies and Southern Power and, in the case of natural gas, distributed by Southern Company Gas, including associated transportation costs, and supplies of such commodities;

demand for energy and the extent of additional supplies of energy available from current or new competitors;

liquidity in the general wholesale electricity and natural gas markets;

weather conditions impacting demand for electricity and natural gas;

seasonality;

transmission or transportation constraints, disruptions, or inefficiencies;

availability of competitively priced alternative energy sources;

forced or unscheduled plant outages for the Southern Company system, its competitors, or third party providers;

the financial condition of market participants;

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the economy in the Southern Company system's service territory, the nation, and worldwide, including the impact of economic conditions on demand for electricity and the demand for fuels, including natural gas;

natural disasters, wars, embargos, acts of terrorism, and other catastrophic events; and

federal, state, and foreign energy and environmental regulation and legislation.

Certain of these factors could increase the expenses of the traditional electric operating companies, Southern Power, or Southern Company Gas and Southern Company. For the traditional electric operating companies and Southern Company Gas' regulated gas distribution operations, such increases may not be fully recoverable through rates. Other of these factors could reduce the revenues of the traditional electric operating companies, Southern Power, or Southern Company Gas and Southern Company.

Historically, the traditional electric operating companies and Southern Company Gas from time to time have experienced underrecovered fuel and/or purchased gas cost balances and may experience such balances in the future. While the traditional electric operating companies and Southern Company Gas are generally authorized to recover fuel and/or purchased gas costs through cost recovery clauses, recovery may be denied if costs are deemed to be imprudently incurred, and delays in the authorization of such recovery could negatively impact the cash flows of the affected traditional electric operating company or Southern Company Gas and Southern Company.

The registrants are subject to risks associated with a changing economic environment, customer behaviors, including increased energy conservation, and adoption patterns of technologies by the customers of the traditional electric operating companies, Southern Power, and Southern Company Gas.

The consumption and use of energy are fundamentally linked to economic activity. This relationship is affected over time by changes in the economy, customer behaviors, and technologies. Any economic downturn could negatively impact customer growth and usage per customer, thus reducing the sales of energy and revenues. Additionally, any economic downturn or disruption of financial markets, both nationally and internationally, could negatively affect the financial stability of customers and counterparties of the traditional electric operating companies, Southern Power, and Southern Company Gas.

Outside of economic disruptions, changes in customer behaviors in response to energy efficiency programs, changing conditions and preferences, or changes in the adoption of technologies could affect the relationship of economic activity to the consumption of energy.

Both federal and state programs exist to influence how customers use energy, and several of the traditional electric operating companies and Southern Company Gas have PSC or other applicable state regulatory agency mandates to promote energy efficiency. Conservation programs could impact the financial results of the registrants in different ways. For example, if any traditional electric operating company or Southern Company Gas is required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact on such traditional electric operating company or Southern Company Gas and Southern Company. Customers could also voluntarily reduce their consumption of energy in response to decreases in their disposable income, increases in energy prices, or individual conservation efforts.

In addition, the adoption of technology by customers can have both positive and negative impacts on sales. Many new technologies utilize less energy than in the past. However, new electric and natural gas technologies such as electric and natural gas vehicles can create additional demand. The Southern Company system uses best available methods and experience to incorporate the effects of changes in customer behavior, state and federal programs, PSC or other applicable state regulatory agency mandates, and technology, but the Southern Company system's planning processes may not appropriately estimate and incorporate these effects.

All of the factors discussed above could adversely affect Southern Company's, the traditional electric operating companies', Southern Power's, and/or Southern Company Gas' results of operations, financial condition, and liquidity.

The operating results of the registrants are affected by weather conditions and may fluctuate on a seasonal andquarterly basis. In addition, catastrophic events, such as fires, earthquakes, hurricanes, tornadoes, floods, droughts, and storms, could result in substantial damage to or limit the operation of the properties of the traditional electric operating companies, Southern Power, and/or Southern Company Gas and could negatively impact results of operation, financial condition, and liquidity.

Electric power and natural gas supply are generally seasonal businesses. In many parts of the country, demand for power peaks during the summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter months. In most of the areas the traditional electric operating companies serve, electric power sales peak during the summer with a smaller peak during the winter, while in most of the areas Southern Company Gas serves, natural gas demand peaks during the winter. As a result, the overall operating results of the registrants may fluctuate substantially on a seasonal basis. In addition, the traditional electric operating companies, Southern Power, and Southern Company Gas have historically sold less

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power and natural gas when weather conditions are milder. Unusually mild weather in the future could reduce the revenues, net income, and available cash of the affected registrant.

Further, volatile or significant weather events could result in substantial damage to the transmission and distribution lines of the traditional electric operating companies, the generating facilities of the traditional electric operating companies and Southern Power, and the natural gas distribution and storage facilities of Southern Company Gas. The traditional electric operating companies, Southern Power, and Southern Company Gas have significant investments in the Atlantic and Gulf Coast regions and Southern Power has wind and natural gas investments in various states which could be subject to severe weather, as well as solar investments in various states which could be subject to natural disasters. Further, severe drought conditions can reduce the availability of water and restrict or prevent the operation of certain generating facilities.

In the event a traditional electric operating company or Southern Company Gas experiences any of these weather events or any natural disaster or other catastrophic event, recovery of costs in excess of reserves and insurance coverage is subject to the approval of its state PSC or other applicable state regulatory agency. Historically, the traditional electric operating companies from time to time have experienced deficits in their storm cost recovery reserve balances and may experience such deficits in the future. Any denial by the applicable state PSC or other applicable state regulatory agency or delay in recovery of any portion of such costs could have a material negative impact on a traditional electric operating company's or Southern Company Gas' and Southern Company's results of operations, financial condition, and liquidity.

In addition, damages resulting from significant weather events within the service territory of any traditional electric operating company or Southern Company Gas or affecting Southern Power's customers may result in the loss of customers and reduced demand for energy for extended periods. Any significant loss of customers or reduction in demand for energy could have a material negative impact on a traditional electric operating company's, Southern Power's, or Southern Company Gas' and Southern Company's results of operations, financial condition, and liquidity.

Acquisitions, dispositions, or other strategic ventures or investments may not result in anticipated benefits and may present risks not originally contemplated, which may have a material adverse effect on the liquidity, results of operations, and financial condition of Southern Company and its subsidiaries.

Southern Company and its subsidiaries have made significant acquisitions and investments in the past and may in the future make additional acquisitions, dispositions, or other strategic ventures or investments, including the proposed sale by Pivotal Utility Holdings, a wholly-owned subsidiary of Southern Company Gas, of the assets of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, and the potential sale by Southern Power of a 33% equity interest in a newly-formed holding company that owns substantially all of Southern Power's solar assets. Southern Company and its subsidiaries continually seek opportunities to create value through various transactions, including acquisitions or sales of assets. Specifically, Southern Power continually seeks opportunities to execute its strategy to create value through various transactions, including acquisitions and sales of assets, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, and other load-serving entities, as well as commercial and industrial customers.

Southern Company and its subsidiaries may face significant competition for transactional opportunities and anticipated transactions may not be completed on acceptable terms or at all. In addition, these transactions are intended to, but may not, result in the generation of cash or income, the realization of savings, the creation of efficiencies, or the reduction of risk. These transactions may also affect the liquidity, results of operations, and financial condition of Southern Company and its subsidiaries.

These transactions also involve risks, including:

they may not result in an increase in income or provide an adequate return on capital or other anticipated benefits;

they may result in Southern Company or its subsidiaries entering into new or additional lines of business, which may have new or different business or operational risks;

they may not be successfully integrated into the acquiring company's operations and/or internal control processes;

the due diligence conducted prior ~~year.~~to a transaction may not uncover situations that could result in financial or legal exposure or the acquiring company may not appropriately evaluate the likelihood or quantify the exposure from identified risks;

they may result in decreased earnings, revenues, or cash flow;

expected benefits of a transaction may be dependent on the cooperation or performance of a counterparty; or

for the traditional electric operating companies and Southern Company Gas, costs associated with such investments that were expected to be recovered through rates may not be recoverable.

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Southern Company and Southern Company Gas are holding companies and are dependent on cash flows from their respective subsidiaries to meet their ongoing and future financial obligations, including making interest and principal payments on outstanding indebtedness and, for Southern Company, to pay dividends on its common stock.

Southern Company and Southern Company Gas are holding companies and, as such, they have no operations of their own. Substantially all of Southern Company's and Southern Company Gas' respective consolidated assets are held by subsidiaries. A significant portion of Southern Company Gas' debt is issued by its 100%-owned subsidiary, Southern Company Gas Capital, and is fully and unconditionally guaranteed by Southern Company Gas. Southern Company's and Southern Company Gas' ability to meet their respective financial obligations, including making interest and principal payments on outstanding indebtedness, and, for Southern Company, to pay dividends on its common stock, is primarily dependent on the net income and cash flows of their respective subsidiaries and the ability of those subsidiaries to pay upstream dividends or to repay borrowed funds. Prior to funding Southern Company or Southern Company Gas, the respective subsidiaries have regulatory restrictions and financial obligations that must be satisfied, including among others, debt service and preferred stock dividends. These subsidiaries are separate legal entities and have no obligation to provide Southern Company or Southern Company Gas with funds. In addition, Southern Company and Southern Company Gas may provide capital contributions or debt financing to subsidiaries under certain circumstances, which would reduce the funds available to meet their respective financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on Southern Company's common stock.

A downgrade in the credit ratings of any of the registrants, Southern Company Gas Capital, or Nicor Gas could negatively affect their ability to access capital at reasonable costs and/or could require posting of collateral or replacing certain indebtedness.

There are a number of factors that rating agencies evaluate to arrive at credit ratings for the registrants, Southern Company Gas Capital, and Nicor Gas, including capital structure, regulatory environment, the ability to cover liquidity requirements, and other commitments for capital. The registrants, Southern Company Gas Capital, and Nicor Gas could experience a downgrade in their ratings if any rating agency concludes that the level of business or financial risk of the industry or the applicable company has deteriorated. Changes in ratings methodologies by the agencies could also have a negative impact on credit ratings. If one or more rating agencies downgrade any registrant, Southern Company Gas Capital, or Nicor Gas, borrowing costs likely would increase, including automatic increases in interest rates under applicable term loans and credit facilities, the pool of investors and funding sources would likely decrease, ~~was~~and, particularly for any downgrade to below investment grade, significant collateral requirements may be triggered in a number of contracts. Any credit rating downgrades could require altering the mix of debt financing currently used, and could require the issuance of secured indebtedness and/or indebtedness with additional restrictive covenants binding the applicable company.

Uncertainty in demand for energy can result in lower earnings or higher costs. If demand for energy falls short of expectations, it could result in potentially stranded assets. If demand for energy exceeds expectations, it could result in increased costs forpurchasing capacity in the open market or building additional electric generation and transmissionfacilities or natural gas distribution and storage facilities.

Southern Company, the traditional electric operating companies, and Southern Power each engage in a long-term planning process to estimate the optimal mix and timing of new generation assets required to serve future load obligations. Southern Company Gas engages in a long-term planning process to estimate the optimal mix and timing of building new pipelines and storage facilities, replacing existing pipelines, rewatering storage facilities, and entering new markets and/or expanding in existing markets. These planning processes must look many years into the future in order to accommodate the long lead times associated with the permitting and construction of new generation and associated transmission facilities and natural gas distribution and storage facilities. Inherent risk exists in predicting demand this far into the future as these future loads are dependent on many uncertain factors, including economic conditions, customer usage patterns, efficiency programs, and customer technology adoption. Because regulators may not permit the traditional electric operating companies or Southern Company Gas' regulated operating companies to adjust rates to recover the costs of new generation and associated transmission assets and/or new pipelines and related infrastructure in a timely manner or at all, Southern Company and its subsidiaries may not be able to fully recover these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs and the recovery in customers' rates. In addition, under Southern Power's model of selling capacity and energy at negotiated market-based rates under long-term PPAs, Southern Power might not be able to fully execute its business plan if market prices drop below original forecasts. Southern Power and/or the traditional electric operating companies may not be able to extend existing PPAs or find new buyers for existing generation assets as existing PPAs expire, or they may be forced to market these assets at prices lower than originally intended. These situations could have negative impacts on net income and cash flows for the affected registrant.

The traditional electric operating companies are currently obligated to supply power to retail customers and wholesale customers under long-term PPAs. Southern Power is currently obligated to supply power to wholesale customers under long-

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term PPAs. At peak times, the demand for power required to meet this obligation could exceed the Southern Company system's available generation capacity. Market or competitive forces may require that the traditional electric operating companies purchase capacity on the open market or build additional generation and transmission facilities, and for Southern Power to purchase energy or capacity on the open market. Because regulators may not permit the traditional electric operating companies to pass all of these purchase or construction costs on to their customers, the traditional electric operating companies may not be able to recover some or all of these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs of purchased or constructed capacity and the traditional electric operating companies' recovery in customers' rates. Under Southern Power's long-term fixed price PPAs, Southern Power may not be able to recover all of these costs. These situations could have negative impacts on net income and cash flows for the affected registrant.

The businesses of the registrants and Nicor Gas are dependent on their ability to successfully access funds through capital markets and financial institutions. Theinability of any of the registrants or Nicor Gas to access funds may limit its ability to execute its business plan by impacting its ability to fund capital investments or acquisitions that it may otherwise rely on to achieve future earnings and cash flows.

The registrants and Nicor Gas rely on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from their respective operations. If any of the registrants or Nicor Gas is not able to access capital at competitive rates or on favorable terms, its ability to implement its business plan will be limited by impacting its ability to fund capital investments or acquisitions that it may otherwise rely on to achieve future earnings and cash flows. In addition, the registrants and Nicor Gas rely on committed bank lending agreements as back-up liquidity which allows them to access low cost money markets. Each of the registrants and Nicor Gas believes that it will maintain sufficient access to these financial markets based upon current credit ratings. However, certain events or market disruptions may increase the cost of borrowing or adversely affect the ability to raise capital through the issuance of securities or other borrowing arrangements or the ability to secure committed bank lending agreements used as back-up sources of capital. Such disruptions could include:

an economic downturn or uncertainty;

bankruptcy or financial distress at an unrelated energy company, financial institution, or sovereign entity;

capital markets volatility and disruption, either nationally or internationally;

changes in tax policy;

volatility in market prices for electricity and natural gas;

terrorist attacks or threatened attacks on the Southern Company system's facilities or unrelated energy companies' facilities;

war or threat of war; or

the overall health of the utility and financial institution industries.

As of December 31, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $911 million primarily due to a ~~14.3% decrease~~$900 million unsecured term loan that matures on March 31, 2018. Mississippi Power expects to refinance the unsecured term loan with external security issuances and/or borrowings from financial institutions or Southern Company. Mississippi Power has been informed by Southern Company that in the ~~average~~event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity to fund the remaining indebtedness to mature and other cash needs over the next 12 months.

Georgia Power's ability to make future borrowings through its term loan credit facility with the Federal Financing Bank is subject to the satisfaction of customary conditions, as well as certification of compliance with the requirements of the loan guarantee program under Title XVII of the Energy Policy Act of 2005, including accuracy of project-related representations and warranties, delivery of updated project-related information and evidence of compliance with 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 certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program. Prior to obtaining any further advances under Georgia Power's loan guarantee agreement with the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement.

Failure to comply with debt covenants or conditions could adversely affect the ability of the registrants, Southern Company Gas Capital, or Nicor Gas to execute future borrowings.

The debt and credit agreements of the registrants, Southern Company Gas Capital, and Nicor Gas contain various financial and other covenants. Georgia Power's loan guarantee agreement with the DOE contains additional covenants, events of default, and mandatory prepayment events relating to the construction of Plant Vogtle Units 3 and 4. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements, which would negatively affect the applicable company's financial condition and liquidity.

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Volatility in the securities markets, interest rates, and other factors could substantially increase defined benefit pension and other postretirement plan costs and the costs of nuclear decommissioning.

The costs of providing pension and other postretirement benefit plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in actuarial assumptions, future government regulation, changes in life expectancy, and the frequency and amount of the Southern Company system's required or voluntary contributions made to the plans. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund the pension and other postretirement plans, if not offset or mitigated by a decline in plan liabilities, could increase pension and other postretirement expense, and the Southern Company system could be required from time to time to fund the pension plans with significant amounts of cash. Such cash funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations. Additionally, Alabama Power and Georgia Power each hold significant assets in their nuclear decommissioning trusts to satisfy obligations to decommission Alabama Power's and Georgia Power's nuclear plants. The rate of return on assets held in those trusts can significantly impact both the costs of decommissioning and the funding requirements for the trusts.

The registrants are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.

The financial condition of some insurance companies, the threat of terrorism, and natural disasters, among other things, could have disruptive effects on insurance markets. The availability of insurance covering risks that the registrants and their respective competitors typically insure against may decrease, and the insurance that the registrants are able to obtain may have higher deductibles, higher premiums, and more restrictive policy terms. Further, the insurance policies may not cover all of the potential exposures or the actual amount of loss incurred.

Any losses not covered by insurance, or any increases in the cost ~~per KWH purchased primarily~~of applicable insurance, could adversely affect the results of operations, cash flows, or financial condition of the affected registrant.

The use of derivative contracts by Southern Company and its subsidiaries in thenormal course of business could result in financial losses that negatively impact thenet income of the registrants or in reported net income volatility.

Southern Company and its subsidiaries, including the traditional electric operating companies, Southern Power, and Southern Company Gas, use derivative instruments, such as swaps, options, futures, and forwards, to manage their commodity and interest rate exposures and, to a lesser extent, manage foreign currency exchange rate exposure and engage in limited trading activities. The registrants could recognize financial losses as a result of ~~lower natural~~volatility in the market values of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, limits, and procedures, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. The factors used in the valuation of these instruments become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

In addition, Southern Company Gas utilizes derivative instruments to lock in economic value in wholesale gas ~~prices, partially offset by~~services, which may not qualify or are not designated as hedges for accounting purposes. The difference in accounting treatment for the underlying position and the financial instrument used to hedge the value of the contract can cause volatility in reported net income of Southern Company and Southern Company Gas while the positions are open due to mark-to-market accounting.

Future impairments of goodwill or long-lived assets could have a ~~5.3%~~material adverse effect on the registrants' results of operations.

Goodwill is assessed for impairment at least annually and more frequently if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value and long-lived assets are assessed for impairment whenever events or circumstances indicate that an asset's carrying amount may not be recoverable. In connection with the completion of the Merger, the application of the acquisition method of accounting was pushed down to Southern Company Gas. The excess of the purchase price over the fair values of Southern Company Gas' assets and liabilities was recorded as goodwill. This resulted in a significant increase in the ~~volume of KWHs purchased.~~goodwill recorded on Southern Company's and Southern Company Gas' consolidated balance sheets. At December 31, 2017, goodwill was $6.3 billion and $6.0 billion for Southern Company and Southern Company Gas, respectively.

In ~~2014,~~addition, Southern Company and its subsidiaries have long-lived assets recorded on their balance sheets. To the extent the value of goodwill or long-lived assets become impaired, the affected registrant may be required to incur impairment charges that could have a material impact on their results of operations. For example, a wholly-owned subsidiary of Southern Company

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Gas owns and operates a natural gas storage facility consisting of two salt dome caverns where recent seismic mapping indicates that proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. Early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. In addition, a subsidiary of Southern Company has several leveraged lease agreements, with terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. With respect to Southern Company's subsidiary's investments in leveraged leases, the recovery of its investment is dependent on the profitable operation of the leased assets by the respective lessees. A significant deterioration in the performance of the leased asset could result in the impairment of the related lease receivable.

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Item 1B.	UNRESOLVED STAFF COMMENTS.

None.

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Item 2. PROPERTIES

Electric

Electric Properties

The traditional electric operating companies, Southern Power, and SEGCO, at December 31, 2017, owned and/or operated 33 hydroelectric generating stations, 29 fossil fuel generating stations, three nuclear generating stations, 15 combined cycle/cogeneration stations, 35 solar facilities, eight wind facilities, one biomass facility, and one landfill gas facility. The amounts of capacity for each company, as of December 31, 2017, are shown in the table below.



Generating Station	Location	Nameplate Capacity (1)
		(KWs)
FOSSIL STEAM
Gadsden	Gadsden, AL	120,000
Gorgas	Jasper, AL	1,021,250
Barry	Mobile, AL	1,300,000
Greene County	Demopolis, AL	300,000	(2	)
Gaston Unit 5	Wilsonville, AL	880,000
Miller	Birmingham, AL	2,532,288	(3	)
Alabama Power Total		6,153,538
Bowen	Cartersville, GA	3,160,000
Hammond	Rome, GA	800,000
McIntosh	Effingham County, GA	163,117
Scherer	Macon, GA	750,924	(4	)
Wansley	Carrollton, GA	925,550	(5	)
Yates	Newnan, GA	700,000
Georgia Power Total		6,499,591
Crist	Pensacola, FL	970,000
Daniel	Pascagoula, MS	500,000	(6	)
Scherer Unit 3	Macon, GA	204,500	(4	)
Gulf Power Total		1,674,500
Daniel	Pascagoula, MS	500,000	(6	)
Greene County	Demopolis, AL	200,000	(2	)
Watson	Gulfport, MS	862,000
Mississippi Power Total		1,562,000
Gaston Units 1-4	Wilsonville, AL
SEGCO Total		1,000,000	(7	)
Total Fossil Steam		16,889,629
NUCLEAR STEAM
Farley	Dothan, AL
Alabama Power Total		1,720,000
Hatch	Baxley, GA	899,612	(8	)
Vogtle Units 1 and 2	Augusta, GA	1,060,240	(9	)
Georgia Power Total		1,959,852
Total Nuclear Steam		3,679,852
COMBUSTION TURBINES
Greene County	Demopolis, AL
Alabama Power Total		720,000
Boulevard	Savannah, GA	19,700

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Generating Station	Location	Nameplate Capacity (1)
McDonough Unit 3	Atlanta, GA	78,800
McIntosh Units 1 through 8	Effingham County, GA	640,000
McManus	Brunswick, GA	481,700
Robins	Warner Robins, GA	158,400
Wansley	Carrollton, GA	26,322	(5	)
Wilson	Augusta, GA	354,100
Georgia Power Total		1,759,022
Lansing Smith Unit A	Southport, FL	39,400
Pea Ridge Units 1 through 3	Pea Ridge, FL	15,000
Gulf Power Total		54,400
Chevron Cogenerating Station	Pascagoula, MS	147,292	(10	)
Sweatt	Meridian, MS	39,400
Watson	Gulfport, MS	39,360
Mississippi Power Total		226,052
Addison	Thomaston, GA	668,800
Cleveland County	Cleveland County, NC	720,000
Dahlberg	Jackson County, GA	756,000
Oleander	Cocoa, FL	791,301
Rowan	Salisbury, NC	455,250
Southern Power Total		3,391,351
Gaston (SEGCO)	Wilsonville, AL	19,680	(7	)
Total Combustion Turbines		6,170,505
COGENERATION
Washington County	Washington County, AL	123,428
Lowndes County	Burkeville, AL	104,800
Theodore	Theodore, AL	236,418
Alabama Power Total		464,646
COMBINED CYCLE
Barry	Mobile, AL
Alabama Power Total		1,070,424
McIntosh Units 10&11	Effingham County, GA	1,318,920
McDonough-Atkinson Units 4 through 6	Atlanta, GA	2,520,000
Georgia Power Total		3,838,920
Lansing Smith Unit 3	Southport, FL
Gulf Power Total		545,500

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Generating Station	Location	Nameplate Capacity (1)
Daniel	Pascagoula, MS	1,070,424
Kemper County/Ratcliffe	Kemper County, MS	769,898	(11)
Mississippi Power Total		1,840,322
Franklin	Smiths, AL	1,857,820
Harris	Autaugaville, AL	1,318,920
Mankato	Mankato, MN	375,000
Rowan	Salisbury, NC	530,550
Stanton Unit A	Orlando, FL	428,649	(12	)
Wansley	Carrollton, GA	1,073,000
Southern Power Total		5,583,939
Total Combined Cycle		12,879,105
HYDROELECTRIC FACILITIES
Bankhead	Holt, AL	53,985
Bouldin	Wetumpka, AL	225,000
Harris	Wedowee, AL	132,000
Henry	Ohatchee, AL	72,900
Holt	Holt, AL	46,944
Jordan	Wetumpka, AL	100,000
Lay	Clanton, AL	177,000
Lewis Smith	Jasper, AL	157,500
Logan Martin	Vincent, AL	135,000
Martin	Dadeville, AL	182,000
Mitchell	Verbena, AL	170,000
Thurlow	Tallassee, AL	81,000
Weiss	Leesburg, AL	87,750
Yates	Tallassee, AL	47,000
Alabama Power Total		1,668,079
Bartletts Ferry	Columbus, GA	173,000
Goat Rock	Columbus, GA	38,600
Lloyd Shoals	Jackson, GA	14,400
Morgan Falls	Atlanta, GA	16,800
North Highlands	Columbus, GA	29,600
Oliver Dam	Columbus, GA	60,000
Rocky Mountain	Rome, GA	215,256	(13	)
Sinclair Dam	Milledgeville, GA	45,000
Tallulah Falls	Clayton, GA	72,000
Terrora	Clayton, GA	16,000
Tugalo	Clayton, GA	45,000
Wallace Dam	Eatonton, GA	321,300
Yonah	Toccoa, GA	22,500
6 Other Plants	Various Georgia locations	18,080
Georgia Power Total		1,087,536
Total Hydroelectric Facilities		2,755,615

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Generating Station	Location	Nameplate Capacity (1)
RENEWABLE SOURCES:
SOLAR FACILITIES
Fort Benning	Columbus, GA	30,000
Fort Gordon	Augusta, GA	30,000
Fort Stewart	Fort Stewart, GA	30,000
Kings Bay	Camden County, GA	30,000
Dalton	Dalton, GA	6,012
3 Other Plants	Various Georgia locations	2,984
Georgia Power Total		128,996
Adobe	Kern County, CA	20,000
Apex	North Las Vegas, NV	20,000
Boulder I	Clark County, NV	100,000	(14	)
Butler	Taylor County, GA	103,700
Butler Solar Farm	Taylor County, GA	22,000
Calipatria	Imperial County, CA	20,000
Campo Verde	Imperial County, CA	147,420
Cimarron	Springer, NM	30,640
Decatur County	Decatur County, GA	20,000
Decatur Parkway	Decatur County, GA	84,000
Desert Stateline	San Bernadino County, CA	299,900	(14	)
East Pecos	Pecos County, TX	120,000
Garland	Kern County, CA	205,130	(14	)
Granville	Oxford, NC	2,500
Henrietta	Kings County, CA	102,000	(14	)
Imperial Valley	Imperial County, CA	163,200	(14	)
Lamesa	Dawson County, TX	102,000
Lost Hills - Blackwell	Kern County, CA	33,440	(14	)
Macho Springs	Luna County, NM	55,000
Morelos del Sol	Kern County, CA	15,000
North Star	Fresno County, CA	61,600	(14	)
Pawpaw	Taylor County, GA	30,480
Roserock	Pecos County, TX	160,000	(14	)
Rutherford	Rutherford County, NC	74,800
Sandhills	Taylor County, GA	146,890
Spectrum	Clark County, NV	30,240
Tranquillity	Fresno County, CA	205,300	(14	)
Southern Power Total		2,375,240	(15	)
Total Solar		2,504,236

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Generating Station	Location	Nameplate Capacity (1)
WIND FACILITIES
Bethel	Castro County, TX	276,000
Grant Plains	Grant County, OK	147,200
Grant Wind	Grant County, OK	151,800
Kay Wind	Kay County, OK	299,000
Passadumkeag	Penobscot County, ME	42,900
Salt Fork	Donley & Gray Counties TX	174,000
Tyler Bluff	Cooke County, TX	125,580
Wake Wind	Crosby & Floyd Counties, TX	257,250	(14	)
Southern Power Total		1,473,730
LANDFILL GAS FACILITY
Perdido	Escambia County, FL
Gulf Power Total		3,200
BIOMASS FACILITY
Nacogdoches	Sacul, TX
Southern Power Total		115,500
Total Generating Capacity		46,936,018

Notes:



(1)	See "Jointly-Owned Facilities" herein for additional information.
(2)	Owned by Alabama Power and Mississippi Power as tenants in common in the proportions of 60% and 40%, respectively.
(3)	Capacity shown is Alabama Power's portion (95.92%) of total plant capacity.
(4)	Capacity shown for Georgia Power is 8.4% of Units 1 and 2 and 75% of Unit 3. Capacity shown for Gulf Power is 25% of Unit 3.
(5)	Capacity shown is Georgia Power's portion (53.5%) of total plant capacity.
(6)	Represents 50% of Plant Daniel Units 1 and 2, which are owned as tenants in common by Gulf Power and Mississippi Power.
(7)	SEGCO is jointly-owned by Alabama Power and Georgia Power. See BUSINESS in Item 1 herein for additional information.
(8)	Capacity shown is Georgia Power's portion (50.1%) of total plant capacity.
(9)	Capacity shown is Georgia Power's portion (45.7%) of total plant capacity.
(10)	Generation is dedicated to a single industrial customer.
(11)	The capacity shown is the gross capacity using natural gas fuel without supplemental firing.
(12)	Capacity shown is Southern Power's portion (65%) of total plant capacity.
(13)	Capacity shown is Georgia Power's portion (25.4%) of total plant capacity. OPC operates the plant.
(14)	Each facility is owned by Southern Power through a majority-owned subsidiary (90.1% Wake Wind, 66% Desert Stateline, and 51% for each of the following facilities: Boulder 1, Garland, Henrietta, Imperial Valley, Lost Hills-Blackwell, North Star, Roserock, and Tranquillity). The capacity shown in the table is 100% of the nameplate capacity for the respective facility.
(15)	Southern Power is pursuing the sale of a 33% equity interest in a newly-formed holding company that owns substantially all of Southern Power's solar assets, which, if successful, is expected to close in the middle of 2018.

Except as discussed below under "Titles to Property," the principal plants and other important units of the traditional electric operating companies, Southern Power, and SEGCO are owned in fee by the respective companies. It is the opinion of management of each such company that its operating properties are adequately maintained and are substantially in good operating condition, and suitable for their intended purpose.

Mississippi Power owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States Louisiana, LLC. The line, completed in 1984, extends from Plant Daniel to the Louisiana state line. Entergy Gulf States Louisiana, LLC is

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paying a use fee over a 40-year period covering all expenses and the amortization of the original $57 million cost of the line. At December 31, 2017, the unamortized portion of this cost was approximately $13 million.

Mississippi Power owns a lignite mine and equipment that were intended to provide fuel for the Kemper IGCC. Mississippi Power also has acquired mineral reserves located around the Kemper County energy facility. The mine, operated by North American Coal Corporation, started commercial operation in 2013. Liberty Fuels Company, LLC, the operator of the mine, has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. Mississippi Power expects mine reclamation activities to begin in 2018. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility – Lignite Mine and CO₂ Pipeline Facilities" of Mississippi Power in Item 7 herein and Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility – Lignite Mine and CO₂ Pipeline Facilities" in Item 8 herein for additional information on the lignite mine.

In 2018, Mississippi Power will file a reserve margin plan which could impact Mississippi Power's generating stations as well as the generating stations jointly owned by Mississippi Power and other traditional electric operating companies. See BUSINESS in Item 1 herein under "Rate Matters – Integrated Resource Planning – Mississippi Power" for additional information.

In 2017, the maximum demand on the traditional electric operating companies, Southern Power, and SEGCO was 34,874,000 KWs and occurred on August 17, 2017. The all-time maximum demand of 38,777,000 KWs on the traditional electric operating companies, Southern Power, and SEGCO occurred on August 22, 2007. These amounts exclude demand served by capacity retained by MEAG Power, OPC, and SEPA. The reserve margin for the traditional electric operating companies, Southern Power, and SEGCO in 2017 was 30.8%. See SELECTED FINANCIAL DATA in Item 6 herein for additional information.

Jointly-Owned Facilities

Alabama Power, Georgia Power, and Southern Power at December 31, 2017 had undivided interests in certain generating plants and other related facilities with non-affiliated parties. The percentages of ownership of the total plant or facility are as follows:



		Percentage Ownership
	Total Capacity	Alabama Power		Power South		Georgia Power		OPC		MEAG Power		Dalton		Southern Power		OUC		FMPA		KUA
	(MWs)
Plant Miller Units 1 and 2	1,320	91.8	%	8.2	%	—	%	—	%	—	%	—	%	—	%	—	%	—	%	—	%
Plant Hatch	1,796	—		—		50.1		30.0		17.7		2.2		—		—		—		—
Plant Vogtle Units 1 and 2	2,320	—		—		45.7		30.0		22.7		1.6		—		—		—		—
Plant Scherer Units 1 and 2	1,636	—		—		8.4		60.0		30.2		1.4		—		—		—		—
Plant Wansley	1,779	—		—		53.5		30.0		15.1		1.4		—		—		—		—
Rocky Mountain	848	—		—		25.4		74.6		—		—		—		—		—		—
Plant Stanton A	660	—		—		—		—		—		—		65.0		28.0		3.5		3.5

Alabama Power and Georgia Power have contracted to operate and maintain the respective units in which each has an interest (other than Rocky Mountain) as agent for the joint owners. SCS provides operation and maintenance services for Plant Stanton A. Southern Nuclear operates and provides services to Alabama Power's and Georgia Power's nuclear plants.

In addition, Georgia Power has commitments regarding a portion of a 5% interest in Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the later of retirement of the plant or the latest stated maturity date of MEAG Power's bonds issued to finance such ownership interest. The payments for capacity are required whether any capacity is available. The energy cost is a function of each unit's variable operating costs. Except for the portion of the capacity payments related to the Georgia PSC's disallowances of Plant Vogtle Units 1 and 2 costs, the cost of such capacity and energy is included in purchased power ~~expense was $672 million, an increase~~from non-affiliates in Georgia Power's statements of ~~$211 million, or 45.8%, as compared~~income in Item 8 herein. Also see Note 7 to the ~~prior year.~~ financial statements of Georgia Power under "Commitments – Fuel and Purchased Power Agreements" in Item 8 herein for additional information.

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Construction continues on Plant Vogtle Units 3 and 4, which are jointly owned by the Vogtle Owners (with each owner holding the same undivided ownership interest as shown in the table above with respect to Plant Vogtle Units 1 and 2). See Note 3 to the financial statements of Southern Company and Georgia Power under "Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 herein.

Titles to Property

The ~~increase~~traditional electric operating companies', Southern Power's, and SEGCO's interests in the principal plants (other than certain pollution control facilities and the land on which five combustion turbine generators of Mississippi Power are located, which is held by easement) and other important units of the respective companies are owned in fee by such companies, subject only to the (1) liens pursuant to pollution control revenue bonds of Gulf Power on specific pollution control facilities at Plant Daniel, (2) liens pursuant to the assumption of debt obligations by Mississippi Power in connection with the acquisition of Plant Daniel Units 3 and 4, (3) liens pursuant to the agreements entered into with Mississippi Power's largest customer, Chevron Products Company (Chevron), on October 4, 2017, on the co-generation assets located at the Chevron refinery, (4) liens associated with Georgia Power's reimbursement obligations to the DOE under its loan guarantee, which are secured by a first priority lien on (a) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 and (b) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4, and (5) liens associated with two PPAs assumed as part of the acquisition of the Mankato project in October 2016 by Southern Power Company. See Note 6 to the financial statements of Southern Company, Georgia Power, Gulf Power, Mississippi Power, and Southern Power under "Assets Subject to Lien," Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings," and Note 6 to the financial statements of Southern Company and Mississippi Power under "Plant Daniel Revenue Bonds" in Item 8 herein for additional information. The traditional electric operating companies own the fee interests in certain of their principal plants as tenants in common. See "Jointly-Owned Facilities" herein for additional information. Properties such as electric transmission and distribution lines, steam heating mains, and gas pipelines are constructed principally on rights-of-way, which are maintained under franchise or are held by easement only. A substantial portion of lands submerged by reservoirs is held under flood right easements. In addition, certain of the renewable generating facilities occupy or use real property that is not owned, primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental entities.

Natural Gas

Southern Company Gas considers its properties to be adequately maintained, substantially in good operating condition, and suitable for their intended purpose. The following provides the location and general character of the materially important properties that are used by the segments of Southern Company Gas. Substantially all of Nicor Gas' properties are subject to the lien of the indenture securing its first mortgage bonds. See Note 6 to the financial statements of Southern Company Gas under "Long-Term Debt – First Mortgage Bonds" in Item 8 herein for additional information.

Distribution and Transmission Mains – Southern Company Gas' distribution systems transport natural gas from its pipeline suppliers to customers in its service areas. These systems consist primarily of distribution and transmission mains, compressor stations, peak shaving/storage plants, service lines, meters, and regulators. At December 31, 2017, Southern Company Gas' gas distribution operations segment owned approximately 82,000 miles of underground distribution and transmission mains, which are located on easements or rights-of-way that generally provide for perpetual use.

Storage Assets – Gas Distribution Operations– Southern Company Gas owns and operates eight underground natural gas storage facilities in Illinois with a total inventory capacity of approximately 150 Bcf, approximately 135 Bcf of which can be cycled on an annual basis. This system is designed to meet about 50% of the estimated peak-day deliveries and approximately 40% of the normal winter deliveries in Illinois. This level of storage capability provides Nicor Gas with supply flexibility, improves the reliability of deliveries, and helps mitigate the risk associated with seasonal price movements.

Southern Company Gas also has five liquefied natural gas (LNG) plants located in Georgia, New Jersey, and Tennessee with total LNG storage capacity of approximately 7.6 Bcf. In addition, Southern Company Gas owns one propane storage facility in Virginia with storage capacity of approximately 0.3 Bcf. The LNG plants and propane storage facility are used by Southern Company Gas' gas distribution operations segment to supplement natural gas supply during peak usage periods.

Storage Assets – All Other– Southern Company Gas subsidiaries own three high-deliverability natural gas storage and hub facilities that are operated by the gas midstream operations segment. Jefferson Island Storage & Hub, LLC operates a storage facility in Louisiana consisting of two salt dome gas storage caverns. Golden Triangle Storage, Inc. operates a storage facility in Texas consisting of two salt dome caverns. Central Valley Gas Storage, LLC operates a depleted field storage facility in California. In addition, Southern Company Gas has a LNG facility in Alabama that produces LNG for Pivotal LNG, Inc. to support its business of selling LNG as a substitute fuel in various markets.

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In August 2017, in connection with an ongoing integrity project into the salt dome gas storage caverns in Louisiana, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. See FUTURE EARNINGS POTENTIAL – "Other Matters" and Note 3 to the financial statements of Southern Company and Southern Company Gas in Item 8 herein for additional information.

Jointly-Owned Properties– Southern Company Gas' gas midstream operations segment has a 50% undivided ownership interest in a 115-mile pipeline facility in northwest Georgia that was ~~primarily~~placed in service on August 1, 2017. Southern Company Gas also has an agreement to lease its 50% undivided ownership in the pipeline facility. See Note 4 to the financial statements of Southern Company and Southern Company Gas in Item 8 herein for additional information.

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Item 3.	LEGAL PROCEEDINGS

See Note 3 to the financial statements of each registrant in Item 8 herein for descriptions of legal and administrative proceedings discussed therein.


Item 4.	MINE SAFETY DISCLOSURES

Not applicable.

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EXECUTIVE OFFICERS OF SOUTHERN COMPANY

(Identification of executive officers of Southern Company is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2017.

Thomas A. Fanning

Chairman, President, and Chief Executive Officer

Age 60

Elected in 2003. Chairman and Chief Executive Officer since December 2010 and President since August 2010.

Art P. Beattie

Executive Vice President and Chief Financial Officer

Age 63

Elected in 2010. Executive Vice President and Chief Financial Officer since August 2010.

W. Paul Bowers

Executive Vice President

Age 61

Elected in 2001. Executive Vice President since February 2008 and Chief Executive Officer, President, and Director of Georgia Power since January 2011. Chairman of Georgia Power's Board of Directors since May 2014.

S. W. Connally, Jr.

Chairman, President, and Chief Executive Officer of Gulf Power

Age 48

Elected in 2012. Elected Chairman in July 2015 and President, Chief Executive Officer, and Director of Gulf Power since July 2012.

Mark A. Crosswhite

Executive Vice President

Age 55

Elected in 2010. Executive Vice President since July 2012 and President, Chief Executive Officer, and Director of Alabama Power since March 2014. Chairman of Alabama Power's Board of Directors since May 2014. Previously served as Executive Vice President and Chief Operating Officer of Southern Company from July 2012 through February 2014.

Andrew W. Evans

Executive Vice President

Age 51

Elected in July 2016. Executive Vice President since July 2016. President of Southern Company Gas since May 2015 and Chief Executive Officer and Chairman of Southern Company Gas' Board of Directors since January 2016. Previously served as Chief Operating Officer of Southern Company Gas from May 2015 through December 2015 and Executive Vice President and Chief Financial Officer of Southern Company Gas from May 2006 through May 2015.

Kimberly S. Greene

Executive Vice President

Age 51

Elected in 2013. Executive Vice President and Chief Operating Officer since March 2014. Director of Southern Company Gas since July 2016. Previously served as President and Chief Executive Officer of SCS from April 2013 to February 2014. Before rejoining Southern Company, Ms. Greene served at Tennessee Valley Authority as Executive Vice President and Chief Generation Officer from 2011 through April 2013.

James Y. Kerr II

Executive Vice President and General Counsel

Age 53

Elected in 2014. Also serves as Chief Compliance Officer. Before joining Southern Company, Mr. Kerr was a partner with McGuireWoods LLP and a senior advisor at McGuireWoods Consulting LLC from 2008 through February 2014.

Stephen E. Kuczynski

Chairman, President, and Chief Executive Officer of Southern Nuclear

Age 55

Elected in 2011. Chairman, President, and Chief Executive Officer of Southern Nuclear since July 2011.

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Mark S. Lantrip

Executive Vice President

Age 63

Elected in 2014. Chairman, President, and Chief Executive Officer of SCS since March 2014. Previously served as Treasurer of Southern Company from October 2007 to February 2014 and Executive Vice President of SCS from November 2010 to March 2014.

Nancy E. Sykes

Executive Vice President of SCS

Age 49

Elected in 2016. Also serves as Chief Human Resources Officer of SCS. Before joining Southern Company, Ms. Sykes served as vice president and chief human resources officer at United States Steel Corporation from May 2015 to November 2016. Previously served as Vice President, Human Resources Asia-Pacific at Goodyear Tire and Rubber Company from October 2012 until May 2015.

Anthony L. Wilson

Chairman, President, and Chief Executive Officer of Mississippi Power

Age 53

Elected in 2015. President of Mississippi Power since October 2015 and Chief Executive Officer and Director since January 2016. Chairman of Mississippi Power's Board of Directors since August 2016. Previously served as Executive Vice President of Mississippi Power from May 2015 to October 2015 and Executive Vice President of Georgia Power from January 2012 to May 2015.

Christopher C. Womack

Executive Vice President

Age 59

Elected in 2008. Executive Vice President and President of External Affairs since January 2009.

The officers of Southern Company were elected at the first meeting of the directors following the last annual meeting of stockholders held on May 24, 2017, for a term of one year or until their successors are elected and have qualified.

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EXECUTIVE OFFICERS OF ALABAMA POWER

(Identification of executive officers of Alabama Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2017.

Mark A. Crosswhite

Chairman, President, and Chief Executive Officer

Age 55

Elected in 2014. President, Chief Executive Officer, and Director since March 1, 2014. Chairman since May 2014. Previously served as Executive Vice President and Chief Operating Officer of Southern Company from July 2012 through February 2014.

Greg J. Barker

Executive Vice President

Age 54

Elected in 2016. Executive Vice President for Customer Services since February 2016. Previously served as Senior Vice President of Marketing and Economic Development from April 2012 to February 2016.

Philip C. Raymond

Executive Vice President, Chief Financial Officer, and Treasurer

Age 58

Elected in 2010. Executive Vice President, Chief Financial Officer, and Treasurer since August 2010.

Zeke W. Smith

Executive Vice President

Age 58

Elected in 2010. Executive Vice President of External Affairs since November 2010.

James P. Heilbron

Senior Vice President and Senior Production Officer

Age 46

Elected in 2013. Senior Vice President and Senior Production Officer since March 2013. Previously served as Senior Vice President and Senior Production Officer of Southern Power Company from July 2010 to February 2013.

R. Scott Moore

Senior Vice President

Age 50

Elected in 2017. Senior Vice President of Power Delivery since May 2017. Previously served as Vice President of Transmission from August 2012 to May 2017.

The officers of Alabama Power were elected at the meeting of the directors held on April 28, 2017 for a term of one year or until their successors are elected and have qualified, except for Mr. Moore, whose election as Senior Vice President was effective May 20, 2017.

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EXECUTIVE OFFICERS OF MISSISSIPPI POWER

(Identification of executive officers of Mississippi Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2017.

Anthony L. Wilson

Chairman, President, and Chief Executive Officer

Age 53

Elected in 2015. President since October 2015 and Chief Executive Officer and Director since January 2016. Chairman of Mississippi Power's Board since August 2016. Previously served as Executive Vice President from May 2015 to October 2015 and Executive Vice President of Georgia Power from January 2012 to May 2015.

John W. Atherton

Vice President

Age 57

Elected in 2004. Vice President of Corporate Services and Community Relations since October 2012.

A. Nicole Faulk

Vice President

Age 44

Elected in 2015. Vice President of Customer Services Organization effective April 2015. Previously served as Region Vice President for the West Region of Georgia Power from March 2015 through April 2015 and Region Manager for the Metro West Region of Georgia Power from December 2011 to March 2015.

Moses H. Feagin

Vice President, Treasurer, and Chief Financial Officer

Age 53

Elected in 2010. Vice President, Treasurer, and Chief Financial Officer since August 2010.

R. Allen Reaves, Jr.

Vice President

Age 58

Elected in 2010. Vice President and Senior Production Officer since August 2010.

Billy F. Thornton

Vice President

Age 57

Elected in 2012. Vice President of External Affairs since October 2012.

The officers of Mississippi Power were elected at the meeting of the directors held on May 1, 2017 for a term of one year or until their successors are elected and have qualified.

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PART II


Item 5.	MARKET FOR REGISTRANTS' COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

(a)(1) The common stock of Southern Company is listed and traded on the NYSE. The common stock is also traded on regional exchanges across the U.S. The high and low stock prices as reported on the NYSE for each quarter of the past two years were as follows:



	High		Low
2017
First Quarter	$	51.47	$	47.57
Second Quarter	51.97		47.87
Third Quarter	50.80		46.71
Fourth Quarter	53.51		47.92
2016
First Quarter	$	51.73	$	46.00
Second Quarter	53.64		47.62
Third Quarter	54.64		50.00
Fourth Quarter	52.23		46.20

There is no market for the other registrants' common stock, all of which is owned by Southern Company.

(a)(2) Number of Southern Company's common stockholders of record at January 31, 2018: 120,413

Each of the other registrants have one common stockholder, Southern Company.

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(a)(3) Dividends on each registrant's common stock are payable at the discretion of their respective board of directors and depend upon earnings, financial condition, and other factors. The dividends on common stock declared by Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, and Southern Company Gas to their stockholder(s) for the past two years are set forth below. No dividends were declared by Mississippi Power on its common stock in 2016 or 2017. Southern Company Gas' dividends are only shown for periods subsequent to the Merger.



Registrant	Quarter	2017		2016
		(in thousands)
Southern Company	First	$	555,791	$	496,718
	Second	578,525		526,267
	Third	581,501		529,876
	Fourth	584,015		551,110
Alabama Power	First	178,507		191,206
	Second	178,507		191,206
	Third	178,507		191,206
	Fourth	178,507		191,206
Georgia Power	First	320,242		326,269
	Second	320,242		326,269
	Third	320,242		326,269
	Fourth	320,242		326,269
Gulf Power	First	31,250		30,017
	Second	31,250		30,017
	Third	31,250		30,017
	Fourth	71,250		30,017
Southern Power Company	First	79,211		68,082
	Second	79,211		68,082
	Third	79,211		68,082
	Fourth	79,211		68,082
Southern Company Gas	First	110,641		—
	Second	110,641		—
	Third	110,641		62,750
	Fourth	110,641		62,750

The dividend paid per share of Southern Company's common stock was 56.00¢ for the first quarter 2017 and 58.00¢ each for the second, third, and fourth quarters of 2017. In 2016, Southern Company paid a dividend per share of 54.25¢ for the first quarter and 56.00¢ each for the second, third, and fourth quarters.

The traditional electric operating companies and Southern Power Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. The authority of the natural gas distribution utilities to pay dividends to Southern Company Gas is subject to regulation. By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates. Additionally, Elizabethtown Gas is restricted by its policy, as established by the New Jersey Board of Public Utilities, to 70% of its quarterly net income it can dividend to Southern Company Gas. Also, as stipulated in the New Jersey Board of Public Utilities' order approving the Merger, Southern Company Gas is prohibited from paying dividends to its parent company, Southern Company, if Southern Company Gas' senior unsecured debt rating falls below investment grade.

(a)(4) Securities authorized for issuance under equity compensation plans.

See Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

(b) Use of Proceeds

Not applicable.

None.

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Item 6.	SELECTED FINANCIAL DATA



	Page
Southern Company. See "SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA"	II-153
Alabama Power. See "SELECTED FINANCIAL AND OPERATING DATA"	II-233
Georgia Power. See "SELECTED FINANCIAL AND OPERATING DATA"	II-323
Gulf Power. See "SELECTED FINANCIAL AND OPERATING DATA"	II-393
Mississippi Power. See "SELECTED FINANCIAL AND OPERATING DATA"	II-479
Southern Power. See "SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA"	II-544
Southern Company Gas. See "SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA"	II-653


Item 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS



	Page
Southern Company. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS"	II-13
Alabama Power. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS"	II-161
Georgia Power. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS"	II-240
Gulf Power. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS"	II-329
Mississippi Power. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS"	II-400
Southern Power. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS"	II-485
Southern Company Gas. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS"	II-551


Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each of the registrants in Item 7 herein and Note 1 of each of the registrant's financial statements under "Financial Instruments" in Item 8 herein. See also Notes 10 and 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Notes 9 and 10 to the financial statements of Gulf Power, Mississippi Power, and Southern Company Gas, and Notes 8 and 9 to the financial statements of Southern Power in Item 8 herein.

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Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO 2017 FINANCIAL STATEMENTS



	Page
The Southern Company and Subsidiary Companies:
Management's Report on Internal Control Over Financial Reporting	II-8
Report of Independent Registered Public Accounting Firm	II-9
Consolidated Statements of Income for the Years Ended December 31, 2017, 2016, and 2015	II-64
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2017, 2016, and 2015	II-65
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016, and 2015	II-66
Consolidated Balance Sheets at December 31, 2017 and 2016	II-67
Consolidated Statements of Capitalization at December 31, 2017 and 2016	II-69
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2017, 2016, and 2015	II-71
Notes to Financial Statements	II-72

Alabama Power:
Management's Report on Internal Control Over Financial Reporting	II-157
Report of Independent Registered Public Accounting Firm	II-158
Statements of Income for the Years Ended December 31, 2017, 2016, and 2015	II-186
Statements of Comprehensive Income for the Years Ended December 31, 2017, 2016, and 2015	II-187
Statements of Cash Flows for the Years Ended December 31, 2017, 2016, and 2015	II-188
Balance Sheets at December 31, 2017 and 2016	II-189
Statements of Capitalization at December 31, 2017 and 2016	II-191
Statements of Common Stockholder's Equity for the Years Ended December 31, 2017, 2016, and 2015	II-192
Notes to Financial Statements	II-193

Georgia Power:
Management's Report on Internal Control Over Financial Reporting	II-236
Report of Independent Registered Public Accounting Firm	II-237
Statements of Income for the Years Ended December 31, 2017, 2016, and 2015	II-270
Statements of Comprehensive Income for the Years Ended December 31, 2017, 2016, and 2015	II-271
Statements of Cash Flows for the Years Ended December 31, 2017, 2016, and 2015	II-272
Balance Sheets at December 31, 2017 and 2016	II-273
Statements of Capitalization at December 31, 2017 and 2016	II-275
Statements of Common Stockholder's Equity for the Years Ended December 31, 2017, 2016, and 2015	II-276
Notes to Financial Statements	II-277

Gulf Power:
Management's Report on Internal Control Over Financial Reporting	II-326
Report of Independent Registered Public Accounting Firm	II-327
Statements of Income for the Years Ended December 31, 2017, 2016, and 2015	II-353
Statements of Comprehensive Income for the Years Ended December 31, 2017, 2016, and 2015	II-354
Statements of Cash Flows for the Years Ended December 31, 2017, 2016, and 2015	II-355
Balance Sheets at December 31, 2017 and 2016	II-356
Statements of Capitalization at December 31, 2017 and 2016	II-358
Statements of Common Stockholder's Equity for the Years Ended December 31, 2017, 2016, and 2015	II-359
Notes to Financial Statements	II-360

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	Page
Mississippi Power:
Management's Report on Internal Control Over Financial Reporting	II-396
Report of Independent Registered Public Accounting Firm	II-397
Statements of Operations for the Years Ended December 31, 2017, 2016, and 2015	II-431
Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2017, 2016, and 2015	II-432
Statements of Cash Flows for the Years Ended December 31, 2017, 2016, and 2015	II-433
Balance Sheets at December 31, 2017 and 2016	II-434
Statements of Capitalization at December 31, 2017 and 2016	II-436
Statements of Common Stockholder's Equity for the Years Ended December 31, 2017, 2016, and 2015	II-437
Notes to Financial Statements	II-438

Southern Power and Subsidiary Companies:
Management's Report on Internal Control Over Financial Reporting	II-482
Report of Independent Registered Public Accounting Firm	II-483
Consolidated Statements of Income for the Years Ended December 31, 2017, 2016, and 2015	II-508
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2017, 2016, and 2015	II-509
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016, and 2015	II-510
Consolidated Balance Sheets at December 31, 2017 and 2016	II-511
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2017, 2016, and 2015	II-513
Notes to Financial Statements	II-514

Southern Company Gas and Subsidiary Companies:
Management's Report on Internal Control Over Financial Reporting	II-546
Report of Independent Registered Public Accounting Firm	II-547
Consolidated Statements of Income for the Years Ended December 31, 2017, 2016, and 2015	II-593
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2017, 2016, and 2015	II-594
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016, and 2015	II-595
Consolidated Balance Sheets at December 31, 2017 and 2016	II-596
Consolidated Statements of Capitalization at December 31, 2017 and 2016	II-598
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2017, 2016, and 2015	II-599
Notes to Financial Statements	II-600

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Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.


Item 9A.	CONTROLS AND PROCEDURES

Disclosure Controls and Procedures.

As of the end of the period covered by this Annual Report on Form 10-K, Southern Company, Alabama Power, Georgia Power, Gulf 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 Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 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.

Internal Control Over Financial Reporting.

(a) Management's Annual Report on Internal Control Over Financial Reporting.



Management's Report on Internal Control Over Financial Reporting	Page
Southern Company	II-8
Alabama Power	II-157
Georgia Power	II-236
Gulf Power	II-326
Mississippi Power	II-396
Southern Power	II-482
Southern Company Gas	II-546

(b) Attestation Report of the Registered Public Accounting Firm.

The report of Deloitte & Touche LLP, Southern Company's independent registered public accounting firm, regarding Southern Company's Internal Control over Financial Reporting is included on page II-9 of this Form 10-K. This report is not applicable to Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas as these companies are not accelerated filers or large accelerated filers.

There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf 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 fourth quarter 2017 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.


Item 9B.	OTHER INFORMATION

None.

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THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

FINANCIAL SECTION

Table of Contents Index to Financial Statements

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Southern Company and Subsidiary Companies 2017 Annual Report

The management of The Southern Company (Southern Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Under management's supervision, an evaluation of the design and effectiveness of Southern Company's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Company's internal control over financial reporting was effective as of December 31, 2017.

Deloitte & Touche LLP, as auditors of Southern Company's financial statements, has issued an attestation report on the effectiveness of Southern Company's internal control over financial reporting as of December 31, 2017, which is included herein.

/s/ Thomas A. Fanning

Thomas A. Fanning

Chairman, President, and Chief Executive Officer

/s/ Art P. Beattie

Art P. Beattie

Executive Vice President and Chief Financial Officer

February 20, 2018

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders and the Board of Directors of The Southern Company and Subsidiary Companies

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of The Southern Company and Subsidiary Companies (the Company) as of December 31, 2017 and 2016, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements (pages II-64 to II-151) referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting (page II-8). Our responsibility is to express an opinion on these financial statements and an opinion on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a ~~35.3% increase~~test basis, evidence regarding the amounts and disclosures in the ~~average~~financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 20, 2018

We have served as the Company's auditor since 2002.

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DEFINITIONS



Term	Meaning
2012 MPSC CPCN Order	A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing acquisition, construction, and operation of Mississippi Power's Kemper County energy facility
2013 ARP	Alternative Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019
AFUDC	Allowance for funds used during construction
Alabama Power	Alabama Power Company
ARO	Asset retirement obligation
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
Atlanta Gas Light	Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas
Atlantic Coast Pipeline	Atlantic Coast Pipeline, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 5% ownership interest
Bechtel	Bechtel Power Corporation
CCR	Coal combustion residuals
Clean Air Act	Clean Air Act Amendments of 1990
CO₂	Carbon dioxide
COD	Commercial operation date
Contractor Settlement Agreement	The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement
Cooperative Energy	Electric cooperative in Mississippi
CPCN	Certificate of public convenience and necessity
CWIP	Construction work in progress
Dalton Pipeline	A pipeline facility in Georgia in which Southern Company Gas has a 50% undivided ownership interest
DOE	U.S. Department of Energy
Eligible Project Costs	Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the loan guarantee program established under Title XVII of the Energy Policy Act of 2005
EPA	U.S. Environmental Protection Agency
EPC Contractor	Westinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
IGCC	Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility (Plant Ratcliffe)
Interim Assessment Agreement	Agreement entered into by the Vogtle Owners and the EPC Contractor to allow construction to continue after the EPC Contractor's bankruptcy filing
IRS	Internal Revenue Service
ITC	Investment tax credit
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate

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DEFINITIONS

(continued)



Term	Meaning
LIFO	Last-in, first-out
Loan Guarantee Agreement	Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, 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
LTSA	Long-term service agreement
Merger	The merger, effective July 1, 2016, of a wholly-owned, direct subsidiary of Southern Company with and into Southern Company Gas, with Southern Company Gas continuing as the surviving corporation
Mirror CWIP	A regulatory liability used by Mississippi Power to record financing costs associated with construction of the Kemper County energy facility, which were subsequently refunded to customers
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
MPUS	Mississippi Public Utilities Staff
MW	Megawatt
natural gas distribution utilities	Southern Company Gas' seven natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Inc., Elizabethtown Gas, Florida City Gas, Chattanooga Gas Company, and Elkton Gas)
NCCR	Georgia Power's Nuclear Construction Cost Recovery
NDR	Alabama Power's Natural Disaster Reserve
New Jersey BPU	New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
Nicor Gas	Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas
NO_X	Nitrogen oxide
NRC	U.S. Nuclear Regulatory Commission
OCI	Other comprehensive income
PennEast Pipeline	PennEast Pipeline Company, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 20% ownership interest
PowerSecure	PowerSecure, Inc.
power pool	The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid
PSC	Public Service Commission
PTC	Production tax credit
Rate CNP	Alabama Power's Rate Certificated New Plant
Rate CNP Compliance	Alabama Power's Rate Certificated New Plant Compliance
Rate CNP PPA	Alabama Power's Rate Certificated New Plant Power Purchase Agreement
Rate ECR	Alabama Power's Rate Energy Cost Recovery
Rate NDR	Alabama Power's Rate Natural Disaster Reserve
Rate RSE	Alabama Power's Rate Stabilization and Equalization plan
ROE	Return on equity
S&P	S&P Global Ratings, a division of S&P Global Inc.
SCS	Southern Company Services, Inc. (the Southern Company system service company)
SEC	U.S. Securities and Exchange Commission
SEGCO	Southern Electric Generating Company

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DEFINITIONS

(continued)



Term	Meaning
SO₂	Sulfur dioxide
Southern Company Gas	Southern Company Gas and its subsidiaries
Southern Company Gas Capital	Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas
Southern Company system	The Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SEGCO, Southern Nuclear, SCS, Southern Linc, PowerSecure (as of May 9, 2016), and other subsidiaries
Southern Linc	Southern Communications Services, Inc.
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
Tax Reform Legislation	The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018
Toshiba	Toshiba Corporation, parent company of Westinghouse
Toshiba Guarantee	Certain payment obligations of the EPC Contractor guaranteed by Toshiba
traditional electric operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
VCM	Vogtle Construction Monitoring
Vogtle 3 and 4 Agreement	Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4
Vogtle Owners	Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners
Vogtle Services Agreement	The June 9, 2017 services agreement between the Vogtle Owners and the EPC Contractor, as amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear
Westinghouse	Westinghouse Electric Company LLC

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company and Subsidiary Companies 2017 Annual Report

OVERVIEW

Business Activities

The Southern Company (Southern Company or the Company) is a holding company that owns all of the common stock of the traditional electric operating companies and the parent entities of Southern Power and Southern Company Gas and owns other direct and indirect subsidiaries. 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 four traditional electric operating companies are vertically integrated utilities providing electric service in four 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 natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. See FUTURE EARNINGS POTENTIAL – "General" herein for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities.

Many factors affect the opportunities, challenges, and risks of the Southern Company system's electricity and natural gas businesses. These factors include the ability to maintain constructive regulatory environments, to maintain and grow 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, reliability, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems.

The traditional electric operating companies and natural gas distribution utilities have 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 the Southern Company system for the foreseeable future. See Note 3 to the financial statements under "Regulatory Matters" for additional information.

Another major factor affecting the Southern Company system's businesses is the profitability of the competitive market-based wholesale generating business. Southern Power's strategy is to create value through various transactions including acquisitions and sales of assets, 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 has committed to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities. Southern Power is also currently pursuing the sale of a portion of equity interests in its solar assets. See FUTURE EARNINGS POTENTIAL – "General" herein for additional information.

Southern Company's other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions include distributed generation systems, utility infrastructure solutions, and energy efficiency products and services. Other business activities also include investments in telecommunications, leveraged lease projects, and gas storage facilities. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions, dispositions, and other strategic ventures or investments accordingly.

In striving to achieve attractive risk-adjusted returns while providing cost-effective energy to more than nine million electric and gas utility customers, the Southern Company system continues to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, execution of major construction projects, and earnings per ~~KWH purchased.~~share (EPS). Southern Company's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the results of the Southern Company system.

See RESULTS OF OPERATIONS herein for information on the Company's financial performance.

~~II-19~~Kemper County Energy Facility Status

The Kemper County energy facility was approved by the Mississippi PSC as an IGCC facility in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

the CO₂ pipeline facilities, AFUDC, and certain general exceptions (Cost Cap Exceptions). The combined cycle and associated common facilities portions of the Kemper County energy facility were placed in service in August 2014. In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), authorizing rates that provided for the recovery of approximately $126 million annually related to the assets previously placed in service.

On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. At the time of project suspension, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants). In the aggregate, Mississippi Power had incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine.

On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement). The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6%, excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with Mississippi Power's Performance Evaluation Plan (PEP), excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).

During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power has begun efforts to dispose of or abandon the mine and gasifier-related assets.

Total pre-tax charges to income related to the Kemper County energy facility were $3.4 billion ($2.4 billion after tax) for the year ended December 31, 2017. In the aggregate, since the Kemper County energy facility project started, Mississippi Power has incurred charges of $6.2 billion ($4.1 billion after tax) through December 31, 2017.

As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.

See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.

Plant Vogtle Units 3 and 4 Status

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

See Note 3 to the financial statements under "Nuclear Construction" for additional information.

Earnings

See Note 12 to the financial statements under "Southern Company – Merger with Southern Company Gas" for additional information regarding the Merger.

Dividends

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

RESULTS OF OPERATIONS

Discussion of the results of operations is divided into three parts – the Southern Company system's primary business of electricity sales, its gas business, and its other business activities.



	Amount
	2017			2016			2015
	(in millions)
Electricity business	$	878		$	2,571		$	2,401
Gas business	243			114			—
Other business activities	(279		)	(237		)	(34		)
Net Income	$	842		$	2,448		$	2,367

Electricity Business

Southern Company's electric utilities generate and sell electricity to retail and wholesale customers.

A condensed statement of income for the electricity business follows:



	Amount			Increase (Decrease) from Prior Year
	2017			2017			2016
	(in millions)
Electric operating revenues	$	18,540		$	599		$	499
Fuel	4,400			39			(389		)
Purchased power	863			113			105
Cost of other sales	69			11			58
Other operations and maintenance	4,340			(183		)	231
Depreciation and amortization	2,457			224			213
Taxes other than income taxes	1,063			24			44
Estimated loss on Kemper IGCC	3,362			2,934			63
Total electric operating expenses	16,554			3,162			325
Operating income	1,986			(2,563		)	174
Allowance for equity funds used during construction	152			(48		)	(26		)
Interest expense, net of amounts capitalized	1,011			80			157
Other income (expense), net	(83		)	(8		)	(43		)
Income taxes	82			(1,009		)	(235		)
Net income	962			(1,690		)	183
Less:
Dividends on preferred and preference stock of subsidiaries	38			(7		)	(9		)
Net income attributable to noncontrolling interests	46			10			22
Net Income Attributable to Southern Company	$	878		$	(1,693	)	$	170

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Electric Operating Revenues

Electric operating revenues for 2017 were $18.5 billion, reflecting a $599 million increase from 2016. Details of electric operating revenues were as follows:



	Amount
	2017			2016
	(in millions)
Retail electric — prior year	$	15,234		$	14,987
Estimated change resulting from —
Rates and pricing	508			427
Sales decline	(71		)	(35		)
Weather	(281		)	153
Fuel and other cost recovery	(60		)	(298		)
Retail electric — current year	15,330			15,234
Wholesale electric revenues	2,426			1,926
Other electric revenues	681			698
Other revenues	103			83
Electric operating revenues	$	18,540		$	17,941
Percent change	3.3		%	2.9		%

Retail electric revenues increased $96 million, or 0.6%, in 2017 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2017 was primarily due to a Rate RSE increase at Alabama Power effective in January 2017, the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff at Georgia Power, and an increase in retail base rates effective July 2017 at Gulf Power. See Note 3 to the financial statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.

Retail electric revenues increased $247 million, or 1.6%, in 2016 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2016 was primarily due to increases in base tariffs at Georgia Power under the 2013 ARP and the NCCR tariff and increased revenues at Alabama Power under Rate CNP Compliance, all effective January 1, 2016. Also contributing to the increase in rates and pricing for 2016 was the 2015 correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing at Georgia Power and the implementation of rates at Mississippi Power for certain Kemper County energy facility in-service assets, effective September 2015. These increases were partially offset by accruals in 2016 for expected refunds at Alabama Power and Georgia Power. See Note 3 to the financial statements under "Kemper County Energy Facility – Rate Recovery" for additional information.

See Note 3 to the financial statements under "Regulatory Matters – Alabama Power – Rate RSE" and " – Rate CNP Compliance" and "Nuclear Construction" and Note 1 to the financial statements under "General" for additional information. Also see "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales decline and weather.

Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives 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

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Wholesale electric revenues from power sales were as follows:



	2017		2016		2015
	(in millions)
Capacity and other	$	838	$	771	$	875
Energy	1,588		1,155		923
Total	$	2,426	$	1,926	$	1,798

In 2017, wholesale revenues increased $500 million, or 26.0%, as compared to the prior year due to a $433 million increase in energy revenues and a $67 million increase in capacity revenues, primarily at Southern Power. The increase in energy revenues was primarily due to increases in renewable energy sales arising from new solar and wind facilities and non-PPA revenues from short-term sales. The increase in capacity revenues was primarily due to a PPA related to new natural gas facilities and additional customer capacity requirements.

In 2016, wholesale revenues increased $128 million, or 7.1%, as compared to the prior year due to a $232 million increase in energy revenues, partially offset by a $104 million decrease in capacity revenues. The increase in energy revenues was primarily due to increases in short-term sales and renewable energy sales at Southern Power, partially offset by lower fuel prices. The decrease in capacity revenues was primarily due to the expiration of wholesale contracts at Georgia Power and Gulf Power, the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, and unit retirements at Georgia Power, partially offset by an increase due to a new wholesale contract at Alabama Power in the first quarter 2016.

Other Electric Revenues

Other electric revenues decreased $17 million, or 2.4%, and increased $41 million, or 6.2%, in 2017 and 2016, respectively, as compared to the prior years. The 2017 decrease was primarily due to a $15 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts at Georgia Power. The 2016 increase was primarily due to a $14 million increase in customer temporary facilities services revenues and a $12 million increase in outdoor lighting revenues at Georgia Power, primarily attributable to LED conversions.

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2017 and the percent change from the prior year were as follows:



	Total KWHs	Total KWH Percent Change				Weather-Adjusted Percent Change
	2017	2017		2016		2017		2016
	(in billions)
Residential	50.5	(5.3	)%	2.3	%	(0.3	)%	0.2	%
Commercial	52.3	(2.6	)	0.4		(0.9	)	(1.0	)
Industrial	52.8	—		(2.1	)	—		(2.2	)
Other	0.9	(4.0	)	(1.7	)	(3.9	)	(1.7	)
Total retail	156.5	(2.6	)	0.2		(0.4	)%	(1.0	)%
Wholesale	49.0	32.4		21.4
Total energy sales	205.5	3.9	%	3.6	%

Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales decreased 4.2 billion KWHs in 2017 as compared to the prior year. This decrease was primarily due to milder weather and decreased customer usage, partially offset by customer growth. Weather-adjusted residential KWH sales decreased primarily due to decreased customer usage resulting from an increase in penetration of

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

energy-efficient residential appliances and an increase in multi-family housing, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased primarily due to decreased customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial KWH energy sales were flat primarily due to decreased sales in the paper, stone, clay, and glass, transportation, and chemicals sectors, offset by increased sales in the primary metals and textile sectors. Additionally, Hurricane Irma negatively impacted customer usage for all customer classes.

Retail energy sales increased 261 million KWHs in 2016 as compared to the prior year. This increase was primarily due to warmer weather in the third quarter 2016 as compared to the corresponding period in 2015 and customer growth, partially offset by decreased customer usage. The decrease in industrial KWH energy sales was primarily due to decreased sales in the primary metals, chemicals, paper, pipeline, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions constrained growth in the industrial sector in 2016. Weather-adjusted commercial KWH sales decreased primarily due to decreased customer usage resulting from an increase in electronic commerce transactions and energy saving initiatives, partially offset by customer growth. Weather-adjusted residential KWH sales increased primarily due to customer growth, partially offset by decreased customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting. Household income, one of the primary drivers of residential customer usage, had modest growth in 2016.

See "Electric Operating Revenues" above for a discussion of significant changes in wholesale revenues related to changes in price and KWH sales.

Other Revenues

Other revenues increased $20 million, or 24.1%, in 2017 as compared to the prior year. The 2017 increase was primarily due to additional third party infrastructure services.

Other revenues increased $83 million in 2016 as compared to the prior year. The 2016 increase was primarily due to revenues from certain non-regulated sales of products and services by the traditional electric operating companies that were reclassified as other revenues for consistency of presentation on a consolidated basis following the PowerSecure acquisition. In prior periods, these revenues were included in other income (expense), net.

Fuel and Purchased Power Expenses

Fuel costs constitute one of the largest expenses for the electric utilities. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the electric utilities purchase a portion of their electricity needs from the wholesale market.

Details of the Southern Company system's generation and purchased power were as follows:



	2017	2016	2015
Total generation (in billions of KWHs)	194	188	187
Total purchased power (in billions of KWHs)	20	19	13
Sources of generation (percent) —
Gas	46	46	46
Coal	30	33	34
Nuclear	16	16	16
Hydro	2	2	3
Other	6	3	1
Cost of fuel, generated (in cents per net KWH) —
Gas	2.79	2.48	2.60
Coal	2.81	3.04	3.55
Nuclear	0.79	0.81	0.79
Average cost of fuel, generated (in cents per net KWH)	2.44	2.40	2.64
Average cost of purchased power (in cents per net KWH)⁽^*)	5.19	4.81	6.11


(*)	Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

In 2017, total fuel and purchased power expenses were $5.3 billion, an increase of $152 million, or 3.0%, as compared to the prior year. The increase was primarily the result of a $196 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $44 million net decrease in the volume of KWHs generated and purchased.

In 2016, total fuel and purchased power expenses were $5.1 billion, a decrease of $284 million, or 5.3%, as compared to the prior year. The decrease was primarily the result of a $650 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices, partially offset by a $366 million increase 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 – Fuel Cost Recovery" 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.

Fuel

In 2017, fuel expense was $4.4 billion, an increase of $39 million, or 0.9%, as compared to the prior year. The increase was primarily due to a 12.5% increase in the average cost of natural gas per KWH generated and a 2.8% increase in the volume of KWHs generated by natural gas, partially offset by a 7.9% decrease in the volume of KWHs generated by coal and a 7.6% decrease in the average cost of coal per KWH generated.

In 2016, fuel expense was $4.4 billion, a decrease of $389 million, or 8.2%, as compared to the prior year. The decrease was primarily due to a 14.4% decrease in the average cost of coal per KWH generated, a 4.6% decrease in the average cost of natural gas per KWH generated, and a 2.7% decrease in the volume of KWHs generated by coal, partially offset by a 3.5% increase in the volume of KWHs generated by natural gas.

Purchased Power

In 2017, purchased power expense was $863 million, an increase of $113 million, or 15.1%, as compared to the prior year. The increase was primarily due to a 7.9% increase in the average cost per KWH purchased, primarily as a result of higher natural gas prices, and a 5.0% increase in the volume of KWHs purchased.

In 2016, purchased power expense was $750 million, an increase of $105 million, or 16.3%, as compared to the prior year. The increase was primarily due to a 45.6% increase in the volume of KWHs purchased, partially offset by a 21.3% decrease in the average cost per KWH purchased primarily as a result of lower natural gas prices.

Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.

Cost of Other Sales

Cost of other sales were $69 million and $58 million in 2017 and 2016, respectively. These costs were related to certain non-regulated sales of products and services by the traditional electric operating companies that were reclassified as cost of other sales for consistency of presentation on a consolidated basis following the PowerSecure acquisition. In prior periods, these costs were included in other income (expense), net.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses ~~increased $33~~decreased $183 million, or ~~0.8%~~4.0%, in ~~2015~~2017 as compared to the prior year. The decrease was primarily due to cost containment and modernization activities implemented at Georgia Power that contributed to decreases of $85 million in generation maintenance costs, $49 million in other employee compensation and benefits, $46 million in transmission and distribution overhead line maintenance, and $22 million in customer accounts, service, and sales costs. Other factors include a $40 million increase in gains from sales of assets at Georgia Power and a $34 million decrease in scheduled outage and maintenance costs at generation facilities. These decreases were partially offset by a $56 million increase associated with new facilities at Southern Power, a $37 million increase in transmission and distribution costs primarily due to vegetation management at Alabama Power, and $32.5 million resulting from the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with a rate case settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement).

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Other operations and maintenance expenses increased $231 million, or 5.4%, in 2016 as compared to the prior year. The increase was primarily related to ~~an $84~~a $76 million increase in ~~employee compensation~~transmission and ~~benefits including pension costs,~~distribution expenses primarily related to overhead line maintenance, a ~~$62~~$37 million decrease in gains from sales of assets at Georgia Power, a $36 million charge in connection with cost containment activities at Georgia Power, and a $35 million increase at Southern Power associated with new solar and wind facilities placed in service in 2015 and 2016. Additionally, the increase was due to a $19 million increase in generation expenses primarily related to environmental costs, a $19 million increase in business development and support expenses at Southern Power, and an $11 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand-side management programs, partially offset by a $99 million decrease in transmission and distribution costs primarily related to reduced overhead line maintenance and gains from sales of transmission assets and a $32 million decrease in scheduled outage and maintenance costs at generation ~~facilities.~~

~~Other operations and maintenance expenses increased $481~~facilities, partially offset by a $41 million ~~or 12.7%,~~net decrease in 2014 as compared to the prior year. The increase was primarily related to increases of $149 million in scheduled outage costs at generation facilities, $103 million in other generation expenses primarily related to commodity and labor costs, $103 million in transmission and distribution costs primarily related to overhead line maintenance, $42 million in net employee compensation and benefits, including pension ~~costs, and $31 million in customer accounts, service, and sales costs primarily related to customer incentive and demand-side management programs.~~costs.

Production expenses and transmission and distribution expenses fluctuate from year to year due to variations in outage and maintenance schedules and normal changes in the cost of labor and materials.

Depreciation and Amortization

Depreciation and amortization increased ~~$91~~$224 million, or ~~4.7%~~10.0%, in ~~2015~~2017 as compared to the prior year. The increase reflects $203 million related to additional plant in service at the traditional electric operating companies and Southern Power and a $13 million increase in amortization related to environmental compliance at Mississippi Power. The increase was partially offset by a $34 million increase in the reductions in depreciation authorized in Gulf Power's 2013 rate case settlement approved by the Florida PSC as compared to the corresponding period in 2016.

Depreciation and amortization increased $213 million, or 10.5%, in 2016 as compared to the prior year primarily due to ~~the amortization of $120 million of the regulatory liability for other cost of removal obligations in 2014 at Alabama Power and increases in~~ additional plant in service at the traditional electric operating companies and Southern Power, partially offset by a decrease as a result of a reduction in depreciation rates at Alabama Power effective January 1, 2015, a decrease due to unit retirements at Georgia Power, and a reduction in depreciation at Gulf Power as authorized in the 2013 rate case settlement agreement approved by the Florida PSC. See Note 3 to the financial statements under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" for additional information.

Depreciation and amortization increased $43 million, or 2.3%, in 2014 as compared to the prior year primarily due to increases in depreciation rates related to environmental assets and the amortization of certain regulatory assets at Alabama Power and the completion of the amortization of certain regulatory liabilities at Georgia Power. Also contributing to the increase were increases at Southern Power in plant in service related to the addition of solar facilities in 2013 and 2014, an increase related to equipment retirements resulting from accelerated outage work, and additional component depreciation as a result of increased production. These increases were largely offset by the amortization of $120 million of the regulatory liability for other cost of removal obligations at Alabama Power.

See Note 1 to the financial statements under ~~"Regulatory~~"Regulatory Assets and ~~Liabilities"~~Liabilities" and ~~"Depreciation~~"Depreciation and ~~Amortization" and Note 3 to the financial statements under "Retail Regulatory Matters – Alabama Power – Rate CNP" and "– Cost of Removal Accounting Order"~~Amortization" for additional information.

Taxes Other Than Income Taxes

Taxes other than income taxes increased ~~$16~~$24 million, or ~~1.6%~~2.3%, in ~~2015~~2017 as compared to the prior year primarily due to an increase in ~~ad valorem and~~ property ~~taxes.~~taxes due to new facilities at Southern Power.

Taxes other than income taxes increased ~~$47~~$44 million, or ~~5.0%~~4.4%, in ~~2014~~2016 as compared to the prior year primarily due to ~~increases of $34 million~~an increase in ~~municipal franchise fees related~~property taxes due to higher ~~retail revenues~~assessed value of property at the traditional electric operating companies, increases in ~~2014~~state and ~~$16 million~~municipal utility license tax bases at Alabama Power, an increase in payroll taxes ~~primarily related to higher employee benefits.~~at Georgia Power, and an increase in franchise taxes at Mississippi Power.

Estimated Loss on Kemper IGCC

In ~~2015~~2017, 2016, and ~~2014,~~2015, estimated probable losses on the Kemper IGCC of ~~$365~~$3.4 billion, $428 million, and ~~$868~~$365 million, respectively, were recorded at Southern Company. ~~These~~On June 28, 2017, Mississippi Power suspended the gasifier portion of the project and recorded a charge to earnings for the remaining $2.8 billion book value of the gasifier portion of the project. Prior to the suspension, Mississippi Power recorded losses ~~reflect~~for revisions of estimated costs expected to be incurred on ~~Mississippi Power's~~ construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of ~~grants awarded to~~ the ~~project by the~~Initial DOE ~~under the Clean Coal Power Initiative Round 2 (DOE Grants)~~Grants and excluding the ~~cost~~Cost Cap Exceptions.

See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.

Allowance for Equity Funds Used During Construction

AFUDC equity decreased $48 million, or 24.0%, in 2017 as compared to the prior year primarily due to Mississippi Power's suspension of the ~~lignite mine~~Kemper IGCC project in June 2017.

AFUDC equity decreased $26 million, or 11.5%, in 2016 as compared to the prior year primarily due to environmental and ~~equipment,~~generation projects being placed in service at Alabama Power and Gulf Power, partially offset by a higher AFUDC rate and an increase in Kemper County energy facility CWIP subject to AFUDC at Mississippi Power prior to the ~~cost~~suspension of the COgasifier portion of the project.

See Note 3 to the financial statements under "₂Kemper County Energy Facility ~~pipeline facilities, AFUDC,~~" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $80 million, or 8.6%, in 2017 as compared to the prior year primarily due to an increase in average outstanding long-term debt, primarily at Southern Power and ~~certain general exceptions, including change of law, force majeure,~~Georgia Power, and ~~beneficial capital (which exists when~~a $37 million decrease in interest capitalized, primarily at Southern Power and Mississippi Power, ~~demonstrates that the purpose and~~partially offset by a net reduction of $36 million

~~II-20~~

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

~~effect of~~following Mississippi Power's settlement with the ~~construction cost increase is~~IRS related to ~~produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions).~~research and experimental deductions. See Note 35 to the financial statements under ~~"Integrated Coal Gasification Combined Cycle"~~"Unrecognized Tax Benefits" for additional information.

~~Allowance for Equity Funds Used During Construction~~

~~AFUDC equity decreased $19~~Interest expense, net of amounts capitalized increased $157 million, or ~~7.8%~~20.3%, in ~~2015~~2016 as compared to the prior year primarily due to a reduction in the AFUDC rate at Mississippi Power, as well as placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014, partially offset by an increase in construction projects related to environmental and steam generation at Alabama Power.

AFUDC equity increased $55 million, or 28.9%, in 2014 as compared to the prior year primarily due to additional capital expenditures at the traditional operating companies, primarily related to environmental and transmission projects, as well as Mississippi Power placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014.

~~See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information regarding the Kemper IGCC.~~

~~Interest Expense, Net of Amounts Capitalized~~

Interest expense, net of amounts capitalized decreased $20 million, or 2.5%, in 2015 as compared to the prior year primarily due to a decrease of $58 million at Mississippi Power related to the termination of an agreement for SMEPA to purchase a portion of the Kemper IGCC which required the return of SMEPA's deposits at a lower rate of interest than accrued and a $14 million decrease primarily due to an increase in capitalized interest associated with the construction of solar facilities at Southern Power, partially offset by a $46 million increase due to higher average outstanding long-term debt balances at the traditional operating companies.

~~Interest expense, net of amounts capitalized increased $6 million, or 0.8%, in 2014 as compared to the prior year primarily due to a higher amount of outstanding long-term debt and~~ an increase in interest expense ~~resulting from~~at Southern Power related to additional debt issued primarily to fund its growth strategy and continuous construction program, increases in both the ~~deposits received by~~average outstanding long-term debt balance and the average interest rate at the traditional electric operating companies, and the May 2015 termination of an asset purchase agreement between Mississippi Power ~~in January~~ and ~~October 2014 from SMEPA, partially offset by a decrease in~~Cooperative Energy and the resulting reversal of accrued interest ~~expense~~on related ~~to the refinancing of long-term debt at lower rates and an increase in capitalized interest.~~deposits.

See Note 6 to the financial statements for additional information.

Other Income (Expense), Net

Other income (expense), net ~~increased $19~~decreased $8 million, or ~~26.0%~~10.7%, in ~~2015~~2017 as compared to the prior year primarily due to increases in charitable donations. The change also includes an increase of $9$159 million in ~~wholesale operating fee revenues, an increase~~currency losses arising from a translation of ~~$9 million in customer contributions in aid of construction at Georgia Power, and an increase due to Mississippi Power's $7 million settlement with the Sierra Club in 2014, partially~~euro-denominated fixed-rate notes into U.S. dollars, fully offset by ~~a decrease~~an equal change in ~~sales of non-utility property~~gains on the foreign currency hedges that were reclassified from accumulated OCI into earnings at ~~Alabama Power~~.Southern Power.

Other income (expense), net decreased ~~$18~~$43 million, or ~~32.7%~~134.4%, in ~~2014~~2016 as compared to the prior year primarily due to the reclassification of revenues and costs associated with certain non-regulated sales of products and services by the traditional electric operating companies to other revenues and cost of other sales for consistency of presentation on a consolidated basis following the PowerSecure acquisition. The net amounts reclassified were $25 million. Also contributing to the decrease was an $8 million decrease in customer contributions in aid of construction and a $6 million decrease in wholesale operating fee ~~revenues~~revenue at Georgia ~~Power and $7 million associated with Mississippi Power's settlement with the Sierra Club.~~Power.

Income Taxes

Income taxes ~~increased $273 million,~~decreased $1.0 billion, or ~~25.9%~~92.5%, in ~~2015~~2017 as compared to the prior year primarily due to ~~a reduction~~$809 million in tax benefits related to ~~the~~ estimated ~~probable~~ losses on ~~Mississippi Power's construction of~~ the Kemper IGCC ~~recorded~~at Mississippi Power and $346 million in ~~2014 and higher pre-tax earnings, partially offset by increased federal income~~net tax benefits ~~related to ITCs at Southern Power in 2015.~~resulting from the Tax Reform Legislation.

Income taxes ~~increased $118~~decreased $235 million, or ~~12.6%~~17.7%, in ~~2014~~2016 as compared to the prior year primarily due to ~~higher pre-tax earnings, partially offset by an increase in non-taxable AFUDC equity and an increase in~~increased federal income tax benefits related to ITCs ~~on Southern Power~~for solar ~~projects~~plants placed in service and PTCs from wind generation at Southern Power in ~~2014.~~2016.

See Note 5 to the financial statements for additional information.

Gas Business

Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations.

On July 1, 2016, Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company. Prior to the completion of the Merger, Southern Company and Southern Company Gas operated as separate companies. The condensed statements of income herein includes Southern Company Gas' results of operations since July 1, 2016. See Note 12 to the financial statements under "Southern Company – Merger with Southern Company Gas" for additional information regarding the Merger, including certain pro forma results of operations.

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

A condensed statement of income for the gas business follows:



	Amount		Increase (Decrease) from Prior Year
	2017		2017
	(in millions)
Operating revenues	$	3,920	$	2,268
Cost of natural gas	1,601		988
Cost of other sales	29		19
Other operations and maintenance	940		417
Depreciation and amortization	501		263
Taxes other than income taxes	184		113
Total operating expenses	3,255		1,800
Operating income	665		468
Earnings from equity method investments	106		46
Interest expense, net of amounts capitalized	200		119
Other income (expense), net	39		25
Income taxes	367		291
Net income	$	243	$	129

The changes in the table above for Southern Company Gas reflect the 12-month period in 2017 compared to the six-month period following the Merger closing on July 1, 2016. Additionally, earnings from equity method investments include Southern Company Gas' acquisition of a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG) completed in September 2016. See Note 12 to the financial statements under "Southern Company Gas" for additional information on Southern Company Gas' investment in SNG.

Seasonality of Results

During the period from November through March when natural gas usage and operating revenues are generally higher (Heating Season), more customers are connected to Southern Company Gas' distribution systems, and natural gas usage is higher in periods of colder weather. Occasionally in the summer, 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 equally over any given year. Thus, operating results can vary significantly from quarter to quarter as a result of seasonality. For 2017, the percentage of operating revenues and net income generated during the Heating Season (January through March and November through December) were 67.3% and 73.7%, respectively. For July 1, 2016 through December 31, 2016, the percentage of operating revenues and net income generated during the Heating Season (November and December) were 67.1% and 96.5%, respectively. The 2017 net income generated during the Heating Season was significantly impacted by additional tax expense recorded in the fourth quarter resulting from the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein for additional information.

Other Business Activities

Southern Company's other business activities include the parent company (which does not allocate operating expenses to business units), products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, and investments in leveraged lease projects and telecommunications. These businesses are classified in general categories and may comprise ~~one or both of~~ the following subsidiaries: PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure; Southern Company Holdings, Inc. (Southern Holdings) invests in various projects, including leveraged lease ~~projects,~~projects; and ~~SouthernLINC Wireless~~Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast.

~~II-21~~On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure for an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company. See Note 12 to the financial statements under "Southern Company – Acquisition of PowerSecure" for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

~~Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast.~~

On February 24, 2016, Southern Company entered into an Agreement and Plan of Merger to acquire PowerSecure International, Inc. Under the terms of this merger agreement, the stockholders of PowerSecure International, Inc. will be entitled to receive $18.75 in cash for each share of common stock in a transaction with a total purchase price of approximately $431 million. Following this transaction, PowerSecure International, Inc. will become a wholly-owned subsidiary of Southern Company. This transaction is expected to close by the end of the second quarter 2016, subject to, among other items, approval by PowerSecure International, Inc. stockholders and notification, clearance, and reporting requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.

A condensed statement of income for Southern Company's other business activities follows:


	Amount			Increase (Decrease) from Prior Year						Amount			Increase (Decrease) from Prior Year
	2015			2015			2014			2017			2017			2016
	(in millions)									(in millions)
Operating revenues	$	47		$	(14	)	$	9		$	571		$	268		$	256
Cost of other sales										415			223			192
Other operations and maintenance	124			29			27			201			7			70
Depreciation and amortization	14			(2		)	1			52			21			17
Taxes other than income taxes	2			—			—			3			—			1
Total operating expenses	140			27			28			671			251			280
Operating income (loss)	(93		)	(41		)	(19		)	(100		)	17			(24		)
Interest income	1			—			—
Interest expense										483			178			239
Other income (expense), net	(8		)	(18		)	36			(3		)	28			(24		)
Interest expense	66			25			5
Income taxes	(132		)	(56		)	10
Income taxes (benefit)										(307		)	(91		)	(84		)
Net income (loss)	$	(34	)	$	(28	)	$	2		$	(279	)	$	(42	)	$	(203	)

Operating Revenues

Southern Company's non-electric operating revenues for these other business activities ~~decreased $14~~increased $268 million, or ~~23.0%~~88.4%, in ~~2015~~2017 as compared to the prior year. The ~~decrease~~increase was primarily ~~related~~the result of the inclusion of PowerSecure results for the 12-month period in 2017 compared to ~~lower operating revenues at Southern Holdings due to higher billings~~eight months in 2014 related to work performed on a generating plant outage and decreases in revenues at SouthernLINC Wireless related to lower average per subscriber revenue and fewer subscribers due to continued competition in the industry.2016. Non-electric operating revenues for these other ~~businesses~~business activities increased $9$256 million, or ~~17.3%~~544.7%, in ~~2014~~2016 as compared to the prior year. The increase was primarily related to ~~higher operating~~ revenues ~~at Southern Holdings due to higher billings~~from products and services following the acquisition of PowerSecure.

Cost of Other Sales

Cost of other sales increased $223 million and $192 million in 2017 and 2016, respectively. These cost increases were primarily related to ~~work performed~~sales of products and services by PowerSecure, which was acquired on a generating plant outage, partially offset by decreases in revenues at SouthernLINC Wireless related to lower average per subscriber revenue and fewer subscribers due to continued competition in the industry.May 9, 2016.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses for these other business activities increased ~~$29~~$7 million, or ~~30.5%~~3.6%, in ~~2015~~2017 as compared to the prior year. The increase was primarily due to a $44 million increase as a result of the inclusion of PowerSecure results for the 12-month period in 2017 compared to eight months in 2016, partially offset by a $35 million decrease in parent company expenses ~~of $27 million~~ related to the ~~proposed~~ Merger ~~partially offset by lower operating expenses at Southern Holdings due to work performed on a generating plant outage in 2014.~~and the acquisition of PowerSecure. Other operations and maintenance expenses for these other business activities increased ~~$27~~$70 million, or ~~39.7%~~56.5%, in ~~2014~~2016 as compared to the prior year. The increase was primarily due to $47 million in operations and maintenance expenses following the acquisition of PowerSecure and an increase in parent company expenses of $16 million related to ~~insurance proceeds received~~the Merger and the acquisition of PowerSecure.

Interest Expense

Interest expense for these other business activities increased $178 million, or 58.4%, in ~~2013 related~~2017 as compared to ~~a litigation settlement with MC Asset Recovery, LLC and higher operating expenses at Southern Holdings~~the prior year primarily due to ~~work performed on~~an increase in average outstanding long-term debt at the parent company. Interest expense for these other business activities increased $239 million, or 362.1%, in 2016 as compared to the prior year primarily due to an increase in outstanding long-term debt at the parent company primarily relating to financing a ~~generating plant outage.~~portion of the purchase price for the Merger.

Other Income (Expense), Net

Other income (expense), net for these other business activities ~~decreased $18~~increased $28 million in ~~2015~~2017 as compared to the prior year. The increase was primarily due to $30 million of expenses incurred in 2016 associated with bridge financing for the Merger. Other income (expense), net for these other business activities decreased $24 million in 2016 as compared to the prior year. The decrease was primarily due to ~~parent company expenses~~an increase of ~~$14~~$16 million related to the ~~proposed~~bridge financing for the Merger. ~~Other~~

Income Taxes (Benefit)

The income ~~(expense), net~~tax benefit for these other business activities increased ~~$36~~$91 million, or 42.1%, in ~~2014~~2017 as compared to the prior ~~year. The increase was~~year primarily ~~due~~as a result of pre-tax earnings (losses) and net tax benefits related to the ~~restructuring of a leveraged lease investment in the first quarter of 2013 and a decrease in charitable contributions in 2014.~~Tax Reform Legislation. The income tax benefit

~~II-22~~

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

Southern Company has several leveraged lease agreements which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. See Note 1 to the financial statements under "Leveraged Leases" for additional information.

~~Interest Expense~~

~~Interest expense~~ for these other business activities increased ~~$25~~$84 million, or ~~61.0%~~63.6%, in 2015 as compared to the prior year primarily due to an increase in outstanding long-term debt. Interest expense for these other business activities increased $5 million, or 13.9%, in 2014 as compared to 2013 primarily due to an increase in outstanding long-term debt, partially offset by the refinancing of long-term debt at lower rates.

~~Income Taxes~~

Income taxes for these other business activities decreased $56 million, or 73.7%, in 2015 as compared to the prior year primarily as a result of state income tax benefits realized in 2015 and changes in pre-tax earnings (losses). Income taxes for these other business activities increased $10 million, or 11.6%, in 20142016 as compared to the prior year primarily as a result of changes in pre-tax earnings (losses)., partially offset by state income tax benefits realized in 2015.

See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 5 to the financial statements for additional information.

Effects of Inflation

The ~~traditional~~electric operating companies and natural gas distribution utilities are subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Southern Power is party to long-term contracts reflecting market-based rates, including inflation expectations. Any adverse effect of inflation on Southern Company's results of operations has not been substantial in recent years.

FUTURE EARNINGS POTENTIAL

General

The four traditional electric operating companies operate as vertically integrated utilities providing ~~electricity~~electric service to customers within their service ~~areas~~territories in the Southeast. The seven natural gas distribution utilities provide service to customers in their service territories in Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee, and Maryland. Prices for electricity provided and natural gas distributed to retail customers are set by state PSCs or other applicable state regulatory agencies under cost-based regulatory principles. Prices for wholesale electricity sales and natural gas distribution, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Southern Power continues to focus on long-term ~~capacity contracts.~~PPAs. See ACCOUNTING POLICIES – ~~"Application~~"Application of Critical Accounting Policies and Estimates – ~~Electric~~ Utility ~~Regulation"~~Regulation" herein and Note 3 to the financial statements for additional information about regulatory matters. As discussed further herein, in October 2017, a wholly-owned subsidiary of Southern Company Gas entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc.

The results of operations for the past three years are not necessarily indicative of Southern Company's future earnings potential. The level of Southern Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system's primary ~~business~~businesses of selling ~~electricity.~~electricity and distributing natural gas. These factors include the traditional electric operating companies' and the natural gas distribution utilities' ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the ~~completion and subsequent operation of the Kemper IGCC and~~next several years. Plant Vogtle Units 3 and 4 ~~as well as other ongoing~~ construction ~~projects. Other~~and rate recovery are also major ~~factors include~~factors. In addition, the profitability of ~~the~~Southern Power's competitive wholesale business and ~~successfully expanding~~successful additional investments in renewable and other energy ~~projects.~~ projects are also major factors.

On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018, which among other things, reduces the federal corporate income tax rate to 21% and changes rates of depreciation and the business interest deduction. See "Income Tax Matters – Federal Tax Reform Legislation" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Notes 3 and 5 to the financial statements for additional information.

Future earnings for the electricity ~~business~~and natural gas businesses will be driven primarily by customer growth. Earnings in the ~~near term~~electricity business will also depend ~~in part,~~ 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 higher multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings for both the electricity and natural gas businesses are subject to a ~~number~~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~~prices of electricity and natural gas, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, future acquisitions and construction of electric generating facilities, ~~including~~ the impact of ~~ITCs,~~tax credits from renewable energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity and natural gas is ~~partially~~primarily driven by ~~economic growth. The~~the pace of economic growth ~~and electricity demand~~that may be affected by changes in regional and global economic conditions, which may impact future earnings. In addition, the volatility of natural gas prices has a significant impact on the natural gas distribution utilities' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.

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 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

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~~Southern Company and Subsidiary Companies 2015 Annual Report~~

affect the business operations, risks, and financial condition of Southern Company. ~~In addition,~~See Note 12 to the ~~proposed Merger will~~financial statements for additional information regarding Southern Company's recent acquisition and disposition activities.

On October 15, 2017, a wholly-owned subsidiary of Southern Company Gas entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. As of December 31, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.3 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and, as a result, a deferred tax liability has not yet been provided. Through the completion of the asset sales, Southern Company Gas intends to invest less than $0.1 billion in ~~a combined company that~~capital additions required for ordinary business operations of these assets. The completion of each asset sale is subject to ~~various risks~~the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC. Southern Company Gas and South Jersey Industries, Inc. made joint filings on December 22, 2017 and January 16, 2018 with the New Jersey BPU and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018.

In addition, Southern Power is pursuing the sale of a 33% equity interest in a newly-formed holding company that ~~do not currently impact~~owns substantially all of Southern ~~Company.~~Power's solar assets, which, if successful, is expected to close in the middle of 2018.

The ultimate outcome of these matters cannot be determined at this time.

Environmental Matters

The Southern Company system'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. The Southern Company system maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to ~~federal and state~~the transmission system. A major portion of these compliance costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of the environmental ~~statutes~~laws and regulations discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.

New or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' 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 fully recovered in rates on a timely basis for the traditional electric operating companies and the natural gas distribution utilities or through ~~market-based contracts. Environmental compliance spending over~~long-term wholesale agreements for the ~~next several years may differ materially from the amounts estimated. The timing, specific requirements,~~traditional electric operating companies and ~~estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed.~~Southern Power. Further, ~~higher~~increased costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and financial condition. ~~See Note 3 to the financial statements under "Environmental Matters" for additional information.~~

~~Environmental Statutes and Regulations~~

~~General~~

The electric utilities' operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; the Migratory Bird Treaty Act; the Bald and Golden Eagle Protection Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2015, the traditional operating companies had invested approximately $11.4 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of approximately $0.9 billion, $1.1 billion, and $0.7 billion for 2015, 2014, and 2013, respectively. The Southern Company system expects that capital expenditures to comply with environmental statutes and regulations will total approximately $1.8 billion from 2016 through 2018, with annual totals of approximately $0.7 billion, $0.5 billion, and $0.6 billion for 2016, 2017, and 2018, respectively. These estimated expenditures do not include any potential capital expenditures that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO₂ emissions from new, existing, and modified or reconstructed fossil-fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. The Southern Company system also anticipates costs associated with closure in place or by other methods, and ground water monitoring of ash ponds in accordance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are not reflected in the capital expenditures above, as these costs are associated with the Company's asset retirement obligation (ARO) liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.

The Southern Company system's ultimate environmental compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations, including the environmental regulations described below; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and the fuel mix of the electric utilities. Compliance costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time. See "Retail Regulatory Matters – Alabama Power – Environmental Accounting Order" and "Retail Regulatory Matters – Georgia Power – Integrated Resource Plan" herein for additional information on planned unit retirements and fuel conversions at Alabama Power and Georgia Power, respectively.

Compliance with any new federal or state legislation or regulations relating to air, water, and land resources or other environmental and health concerns could significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the electric utilities' operations, the full impact of any such changes cannot be determined at this time. Additionally, many ~~of the electric utilities'~~ 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.~~electricity and natural gas.

~~Air Quality~~

~~Compliance with~~The Southern Company system's commitment to the ~~Clean Air Act and resulting regulations~~environment has been demonstrated in many ways, including participating in partnerships resulting in approximately $126 million of funding that has restored or enhanced more than 1.7 million acres of habitat since 2003; the removal of more than 15 million pounds of trash and ~~will continue~~debris from waterways through the Renew Our Rivers program; a 21% reduction in surface water withdrawal from 2015 to ~~be a significant focus for~~2016; reductions in SO₂ and NO_X air emissions of 95% and 85%, respectively, since 1990; the reduction of mercury air emissions of over 90% since 2005; and the Southern Company ~~system. Additional controls are currently planned or under consideration~~system's changing energy mix.

Through 2017, the traditional electric operating companies have invested approximately $12.9 billion in environmental capital retrofit projects to ~~further reduce air emissions, maintain compliance~~comply with ~~existing regulations,~~environmental requirements, with annual totals of approximately $0.9 billion, $0.5 billion, and ~~meet new requirements.~~

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Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

~~In 2012,~~$0.9 billion for 2017, 2016, and 2015, respectively. Although the ~~EPA finalized the Mercury~~timing, requirements, and ~~Air Toxics Standards (MATS) rule, which imposes stringent emissions limits for acid gases, mercury,~~estimated costs could change as environmental laws and ~~particulate matter on coal-~~regulations are adopted or modified, as compliance plans are revised or updated, and ~~oil-fired electric utility steam generating units. The compliance deadline set by the final MATS rule was April 16, 2015, with provisions for extensions~~as legal challenges to ~~April 16, 2016. The implementation strategy for the MATS rule includes emission controls, retirements, and fuel conversions to achieve compliance by the deadlines applicable to each unit within~~rules are initiated or completed, the Southern Company ~~system. On June 29, 2015,~~system's current compliance strategy estimates capital expenditures of $2.8 billion from 2018 through 2022, with annual totals of approximately $1.1 billion, $0.3 billion, $0.4 billion, $0.5 billion, and $0.5 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimates do not include any potential compliance costs associated with the ~~U.S. Supreme Court issued a decision finding that in developing the MATS rule the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant~~regulation of CO₂ emissions from fossil fuel-fired electric generating units. ~~On December 15, 2015,~~See "Global Climate Issues" herein for additional information. The Southern Company system also anticipates expenditures associated with ash pond closure and ground water monitoring under the ~~U.S. Court~~Disposal of ~~Appeals for~~Coal Combustion Residuals from Electric Utilities rule (CCR Rule), which are reflected in the ~~District of Columbia Circuit remanded the MATS rule~~Company's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the EPA without vacatur to respond to the U.S. Supreme Court's decision. The EPA's supplemental finding in response to the U.S. Supreme Court's decision, which the EPA proposes to finalize in April 2016, is not expected to have any impact on the MATS rule compliance requirementsfinancial statements under "Asset Retirement Obligations and ~~deadlines.~~Other Costs of Removal" for additional information.

Environmental Laws and Regulations

Air Quality

The EPA ~~regulates ground level ozone concentrations through implementation of an eight-hour ozone~~has set National Ambient Air Quality ~~Standard~~Standards (NAAQS). for six air pollutants (carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and SO₂), which it reviews and revises periodically. Revisions to these standards can require additional emission controls, improvements in control efficiency, or fuel changes which can result in increased compliance and operational costs. NAAQS requirements can also adversely affect the siting of new facilities. In 2008, the EPA adopted a revised eight-hour ozone NAAQS, and published its final area designations in 2012. The only area within the traditional operating companies' service territory designated as an ozone nonattainment area for the 2008 standard is a 15-county area within metropolitan Atlanta. On October 26, 2015, the EPA published a more stringent eight-hour ozone NAAQS. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. States will recommend area designations by October 2016, and the EPA is expected to finalize them by October 2017.

The EPA regulates fine particulate matter concentrations on an annual and 24-hour average basis. All areas within the traditional operating companies' service territory have achieved attainment with the 1997 and 2006 particulate matter NAAQS and the EPA has officially redesignated former nonattainment areas within the service territory as attainment for these standards. In 2012, the EPA issued a final rule that increases the stringency of the annual fine particulate matter standard. The EPA promulgated finalplans to complete designations for ~~the 2012 annual standard in December 2014,~~this rule by no later than April 30, 2018 and ~~no new nonattainment areas were designated~~intends to designate an eight-county area within ~~the traditional operating companies' service territory. The EPA has, however, deferred designation decisions for certain areas in Florida and Georgia.~~

~~Final revisions to the NAAQS for sulfur dioxide (SO~~₂~~), which established a new one-hour standard, became effective in 2010.~~metropolitan Atlanta as nonattainment. No other areas within the Southern Company system's electric service territory have been or are anticipated to be designated as nonattainment under ~~this rule. However,~~the 2015 ozone NAAQS. In 2010, the EPA ~~has finalized a data requirements rule to support additional designation decisions~~revised the NAAQS for SO₂, establishing a new one-hour standard, and is completing designations in multiple phases. The EPA has issued several rounds of area designations and no areas in the ~~future, which could result in nonattainment designations for areas within the~~vicinity of Southern Company ~~system's service territory. Implementation of the revised~~system-owned SO₂ ~~standard could require additional reductions in~~sources have been designated nonattainment under the 2010 one-hour SO₂ ~~emissions~~NAAQS. However, final eight-hour ozone and SO₂ one-hour designations for certain areas are still pending and, if other areas are designated as nonattainment in the future, increased compliance ~~and operational costs.~~costs could result.

In ~~February 2014,~~2011, the EPA ~~proposed to delete from~~finalized the Alabama State Implementation Plan (SIP) the Alabama opacity rule that the EPA approved in 2008, which provides operational flexibility to affected units. In 2013, the U.S. Court of Appeals for the Eleventh Circuit ruled in favor of Alabama Power and vacated an earlier attempt by the EPA to rescind its 2008 approval. The EPA's latest proposal characterizes the proposed deletion as an error correction within the meaning of the Clean Air Act. Alabama Power believes this interpretation of the Clean Air Act to be incorrect. If finalized, this proposed action could affect unit availability and result in increased operations and maintenance costs for affected units, including units owned by Alabama Power, units co-owned with Mississippi Power, and units owned by SEGCO, which is jointly owned by Alabama Power and Georgia Power.

~~Each of the states in which the Southern Company system has fossil generation is subject to the requirements of the Cross State~~Cross-State Air Pollution Rule (CSAPR). and its NO_X annual, NO_X seasonal, and SO₂ annual programs. CSAPR is an emissions trading program that ~~limits~~addresses the impacts of the interstate transport of SO₂ and ~~nitrogen oxide~~NO_X emissions from fossil fuel-fired power plants located in 28upwind states in ~~two phases, with Phase I having begun in 2015 and Phase II beginning in 2017. On July 28, 2015,~~the eastern half of the U.S. ~~Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of~~on air quality in downwind states. The Southern Company system has fossil fuel-fired generation in several states ~~including Alabama, Florida, Georgia, North Carolina, and Texas, but rejected all other pending challenges~~subject to ~~the rule. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. On December 3, 2015,~~these requirements. In October 2016, the EPA published a ~~proposed revision to~~final rule that revised the CSAPR ~~that would revise existing ozone-season~~seasonal NO_X program, establishing more stringent NO_X emissions budgets ~~for nitrogen oxide~~ in Alabama, ~~and~~ Mississippi, and ~~would remove Florida~~Texas. The EPA also removed North Carolina from the CSAPR NO_X seasonal program and completely removed Florida from all CSAPR programs. Georgia's seasonal NO_X budget remains unchanged. The outcome of ongoing CSAPR litigation, to which Mississippi Power is a party, could have an impact on the State of Mississippi's allowance allocations under the CSAPR seasonal NO_Xprogram. ~~The EPA proposes to finalize this rulemaking by summer 2016.~~Increases in either future fossil fuel-fired generation or the cost of CSAPR allowances could have a negative financial impact on results of operations for Southern Company.

The EPA finalized regional haze regulations in 2005 ~~with a~~and 2017. These regulations require states, tribal governments, and various federal agencies to develop and implement plans to reduce pollutants that impair visibility and demonstrate reasonable progress toward the goal of restoring natural visibility conditions in certain areas, ~~(primarily~~including national parks and wilderness ~~areas)~~areas. States must submit a revised state implementation plan (SIP) to the EPA by 2064. The rule involves the application of best available retrofit technology to certain sources, including fossil fuel-fired generating facilities, built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieveJuly 31, 2021, demonstrating reasonable progress ~~toward the natural~~towards achieving visibility ~~conditions goal by 2018 and for each 10-year period thereafter.~~improvement goals. State implementation of reasonable progress could require further reductions in SO₂ or NO_X emissions, which could result in increased compliance costs.

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~~Southern Company and Subsidiary Companies 2015 Annual Report~~

~~(including CTs at combined cycle units) during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed.~~

~~On June 12,~~ 2015, the EPA published a final rule requiring certain states (including Alabama, Florida, Georgia, Mississippi, North Carolina, and Texas) to revise or remove the provisions of their SIPs ~~relating to the regulation of~~regulating excess emissions at industrial facilities, including ~~fossil fuel-fired~~electric generating facilities, during periods of startup, shut-down, or malfunction (SSM) ~~by no later than November 22, 2016.~~

. The ~~Southern Company system has developed~~state excess emission rules provide necessary operational flexibility to affected units during periods of SSM and, ~~continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the current~~if removed, could affect unit availability and ~~proposed environmental requirements discussed above. As part of this strategy, certain of the traditional operating companies have developed a compliance plan~~result in increased operations and maintenance costs for the MATS rule which includes reliance on existing emission control technologies, the construction of baghouses to provide an additional level of control on the emissions of mercury and particulates from certain generating units, the use of additives or other injection technology, the use of existing or additional natural gas capability, and unit retirements. Additionally, certain transmission system upgrades are required. The impacts of the eight-hour ozone, fine particulate matter and SO₂~~NAAQS, the Alabama opacity rule, CSAPR, regional haze regulations, the MATS rule, the NSPS for CTs, and the SSM rule on~~ the Southern Company system cannot be determined at this time and will depend on the specific provisions of the proposed and final rules, the resolution of pending and future legal challenges, and/or the development and implementation of rules at the state level. These regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs aresystem. The EPA has not ~~recovered through regulated rates or through PPAs.~~

~~In addition~~yet responded to the ~~federal air quality laws described above, Georgia Power has also been subject to~~SIP revisions proposed by states within the ~~requirements of the 2007 State of Georgia Multi-Pollutant Rule. The Multi-Pollutant Rule and a companion rule required reductions in emissions of mercury, SO~~₂~~, and nitrogen oxide state-wide through the installation of specified control technologies and a 95% reduction in SO~~₂ emissions at certain coal-fired generating units by specific dates between 2008 and 2015. In 2015, Georgia Power completed implementation of the measures necessary to comply with the Georgia Multi-Pollutant Rule at all 16 of its coal-fired generating units required to be controlled under the rule.Southern Company system's traditional electric service territory.

Water Quality

~~The EPA's final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing~~In 2014, the EPA finalized requirements under Section 316(b) of the Clean Water Act (CWA) to regulate cooling water intake structures at existing power plants and manufacturing facilities ~~became effective~~ in ~~October 2014.~~order to minimize their effects on fish and other aquatic life. The ~~effect of this final rule will depend~~regulation requires plant-specific studies to determine applicable measures to protect organisms that either get caught on the results of additional studies and implementation of the rule by regulators based on site-specific factors. National Pollutant Discharge Elimination System permits issued after July 14, 2018 must include conditions to implement and ensure compliance with the standards and protective measures required by the rule. The ultimate impact of this rule will also depend on the outcome of ongoing legal challenges and cannot be determined at this time.

On November 3, 2015, the EPA published a final effluent guidelines rule which imposes stringent technology-based requirements for certain wastestreams from steam electric power plants. The revised technology-based limits and compliance dates will be incorporated into future renewals of National Pollutant Discharge Elimination System permits at affected units and may require the installation and operation of multiple technologies sufficient to ensure compliance with applicable new numeric wastewater compliance limits. Compliance deadlines between November 1, 2018 and December 31, 2023 will be established in permits based on information provided for each applicable wastestream. The ultimate impact of these requirements will depend on pending and any future legal challenges, compliance dates, and implementation of the final rule and cannot be determined at this time.

On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs. The final rule significantly expands the scope of federal jurisdiction under the CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. The rule became effective August 28, 2015, but on October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The ultimate impact of the final rule will depend on the outcome of this and other pending legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.

These water quality regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through PPAs.

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Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

intake screens (impingement) or are drawn into the cooling system (entrainment). The ultimate impact of this rule will depend on the outcome of these plant-specific studies and any additional protective measures required to be incorporated into each plant's National Pollutant Discharge Elimination System (NPDES) permit based on site-specific factors.

In 2015, the EPA finalized the steam electric effluent limitations guidelines (ELG) rule that set national standards for wastewater discharges from steam electric generating units. The rule prohibits effluent discharges of certain wastestreams and imposes stringent arsenic, mercury, selenium, and nitrate/nitrite limits on scrubber wastewater discharges. The revised technology-based limits and compliance dates may require extensive modifications to existing ash and wastewater management systems or the installation and operation of new ash and wastewater management systems. Compliance with the ELG rule is expected to require capital expenditures and increased operational costs primarily affecting the traditional electric operating companies' coal-fired electric generation. Compliance applicability dates range from November 1, 2018 to December 31, 2023 with state environmental agencies incorporating specific applicability dates in the NPDES permitting process based on information provided for each waste stream. The EPA has committed to a new rulemaking that could potentially revise the limitations and applicability dates of the ELG rule. The EPA expects to finalize this rulemaking in 2020.

In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all CWA programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, and canals), which could impact new generation projects and permitting and reporting requirements associated with the installation, expansion, and maintenance of transmission, distribution, and pipeline projects. On July 27, 2017, the EPA and the Corps proposed to rescind the 2015 WOTUS rule. The WOTUS rule has been stayed by the U.S. Court of Appeals for the Sixth Circuit since late 2015, but on January 22, 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction over the pending challenges to the rule. On February 6, 2018, the EPA and the Corps published a final rule delaying implementation of the 2015 WOTUS rule to 2020.

Coal Combustion Residuals

~~The traditional operating companies currently manage CCR at onsite storage units consisting of landfills and surface impoundments (CCR Units) at 22 electric generating plants.~~ In addition to on-site storage, the traditional operating companies also sell a portion of their CCR to third parties for beneficial reuse. Individual states regulate CCR and the states in the Southern Company system's service territory each have their own regulatory requirements. Each traditional operating company has an inspection program in place to assist in maintaining the integrity of its coal ash surface impoundments.

~~On April 17,~~ 2015, the EPA ~~published the CCR Rule in the Federal Register, which became effective on October 19, 2015. The CCR Rule regulates~~finalized non-hazardous solid waste regulations for the disposal of CCR, including coal ash and gypsum, ~~as non-hazardous solid waste~~ in ~~CCR Units~~landfills and surface impoundments (CCR units) at active generating power plants. The CCR Rule ~~does not automatically require closure~~requires CCR units to be evaluated against a set of ~~CCR Units but includes~~performance criteria and potentially closed if minimum criteria ~~for active and inactive surface impoundments containing CCR and liquids, lateral expansions~~are not met. Closure of existing CCR units could require installation of equipment and infrastructure to manage CCR in accordance with the rule. The EPA has announced plans to reconsider certain portions of the CCR Rule by no later than December 2019, which could result in changes to deadlines and corrective action requirements.

The EPA's reconsideration of the CCR Rule is due in part to a legislative development that impacts the potential oversight role of state agencies. Under the Water Infrastructure Improvements for the Nation Act, which became law in 2016, states are allowed to establish permit programs for implementing the CCR Rule. The Georgia Department of Natural Resources has incorporated the requirements of the CCR Rule into its solid waste regulations, which established additional requirements for all of Georgia Power's CCR units, and ~~active landfills. Failure to meet~~has requested that the ~~minimum criteria can result~~EPA approve its state permitting program. The other states in the ~~required closure of a CCR Unit. Although~~Southern Company system's electric service territory have not yet submitted plans to the EPA does not require individual states to adopt the final criteria, states have the option to incorporate the federal criteria into their state solid waste management plans in order to regulate CCR in a manner consistent with federal standards. The EPA's final rule continues to exclude the beneficial use of CCR from regulation.EPA.

Based on ~~initial~~ cost estimates for closure ~~in place or by other methods,~~ and ~~groundwater~~ monitoring of ash ponds pursuant to the CCR Rule, Southern Company recorded ~~incremental~~ AROs ~~related to the~~for each CCR ~~Rule.~~unit in 2015. As further analysis is performed ~~including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site,~~ and ~~the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,~~closure details are developed, the traditional electric operating companies ~~expect to~~will continue to periodically update these ~~estimates. The traditional operating companies are currently completing an analysis of the plan of closure for all ash ponds in the Southern Company system, including the timing of closure~~cost estimates as necessary. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and related cost recovery through regulated rates subject to the traditional operating companies' respective state PSC approval. Based on the results of that analysis, the traditional operating companies may accelerate the timing of some ash pond closures which could increase their ARO liabilities from the amounts presently recorded. The ultimate impact of the CCR Rule cannot be determined at this timeContractual Obligations" herein and will depend on the traditional operating companies' ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Southern Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. See Note 1 to the financial statements under ~~"Asset~~"Asset Retirement Obligations and Other Costs of ~~Removal"~~Removal" for additional information regarding Southern Company's AROs as of December 31, ~~2015.~~2017.

Environmental Remediation

The Southern Company system must comply with ~~other~~ environmental laws and regulations ~~that cover~~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 Southern Company Gas conduct studies to determine the extent of any required cleanup and ~~the~~Southern Company has recognized ~~in its financial statements~~ the estimated costs to clean up known impacted ~~sites.~~sites in its financial statements. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The traditional electric operating companies and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have ~~each~~all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These ~~rates~~regulatory mechanisms are adjusted annually or as necessary within limits approved by the state ~~PSCs.~~PSCs or other applicable state regulatory agencies. The traditional electric operating companies and Southern Company Gas may be liable for some or all required cleanup costs for additional sites ~~that may require environmental remediation. See Note 3 to the financial statements under "Environmental Matters – Environmental Remediation" for additional information.~~

~~Global Climate Issues~~

~~On October 23, 2015, the EPA published two final actions that would limit CO~~₂ ~~emissions from fossil fuel-fired electric generating units. One of the final actions contains specific emission standards governing CO~~₂ ~~emissions from new, modified, and reconstructed units. The other final action, known as the Clean Power Plan, establishes guidelines for states to develop plans to meet EPA-mandated CO~~₂ ~~emission rates or emission reduction goals for existing units. The EPA's final guidelines require state plans to meet interim CO~~₂ performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA published a proposed federal plan and model rule that, when finalized, states can adopt or that would be put in place if a state either does not submit a state plan or its plan is not approved by the EPA. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for its review with the courts. The stay will remain in effect through the resolution of the litigation, whether resolved in the U.S. Court of Appeals for the District of Columbia Circuit or the U.S. Supreme Court.

~~II-27~~

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

~~flows,~~that may require environmental remediation. See Note 3 to the financial statements under "Environmental Matters – Environmental Remediation" for additional information.

Global Climate Issues

In 2015, the EPA published final rules limiting CO₂ emissions from new, modified, and ~~financial condition could be significantly impacted if such costs are not recovered through regulated rates~~reconstructed fossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO₂ emission performance standards for existing units (known as the Clean Power Plan or ~~through PPAs. However,~~CPP). In February 2016, the ~~ultimate financial and operational impact~~U.S. Supreme Court granted a stay of the ~~final rules on~~CPP, which will remain in effect through the ~~Southern Company system cannot be determined at this time~~resolution of litigation in the U.S. Court of Appeals for the District of Columbia challenging the legality of the CPP and ~~will depend upon numerous factors,~~any review by the U.S. Supreme Court. On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including ~~the Southern Company system's ongoing~~ review of the ~~final rules;~~CPP and other CO₂ emissions rules. On October 10, 2017, the ~~outcome~~EPA published a proposed rule to repeal the CPP and, on December 28, 2017, published an advanced notice of ~~legal challenges, including legal challenges filed by~~proposed rulemaking regarding a CPP replacement rule.

In 2015, parties to the ~~traditional operating companies; individual state implementation of the EPA's final guidelines,~~United Nations Framework Convention on Climate Change, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

~~The~~ United ~~Nations 21~~^st~~international climate change conference took place in late 2015. The result was the adoption of~~States, adopted the Paris Agreement, which ~~establishes~~established a non-binding universal framework for addressing greenhouse gas (GHG) emissions based on nationally determined contributions. ~~It also sets in place a process for increasing those commitments every five years.~~On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate impact of this agreement or any renegotiated agreement depends on its ~~ratification and~~ implementation by participating ~~countries~~countries.

Domestic GHG policies may emerge in the future requiring the United States to transition to a lower GHG emitting economy. The Southern Company system has transitioned from an electric generating mix of 71% coal and ~~cannot be determined at this time.~~

~~The EPA's greenhouse~~11% natural gas ~~reporting rule requires annual reporting~~in 2005 to 30% percent coal and 46% natural gas mix in 2017 and currently includes over 8,000 MWs of CO₂ ~~equivalent emissions~~renewable projects. In addition, the Southern Company system has retired 4,226 MWs of coal- and oil-fired generating capacity since 2010 and converted 3,280 MWs of generating capacity from coal to natural gas since 2015. Southern Company Gas replaced 5,300 miles of bare steel and cast-iron pipe, resulting in removal of 2.5 million metric tons ~~for a company's operational control~~ of ~~facilities.~~GHG from its natural gas distribution system since 1998. Based on ownership or financial control of facilities, the Southern Company system's ~~2014 greenhouse gas~~2016 GHG emissions ~~were approximately 112 million metric tons of CO~~(CO₂ ~~equivalent. The~~equivalent) were approximately 99 million metric tons, with 2017 emissions estimated at 96 million metric tons. This equates to a reduction of 27% between 2005 and 2016 and a preliminary estimate of 30% through 2017. To better represent GHG emission reductions, the Southern Company ~~system's 2015 greenhouse gas emissions on~~system is transitioning to a maximum emission baseline year of 2007 and a baseline calculation methodology consistent with the ~~same~~EPA's Greenhouse Gas Reporting Program methodology. On a preliminary basis, ~~is approximately 101 million metric tons~~these baseline adjustments result in an estimated GHG emission reduction of CO₂ ~~equivalent. The level of greenhouse gas emissions~~36% from ~~year to year will depend on the level of generation, the mix of fuel sources, and other factors.~~2007 through 2017.

FERC Matters

Market-Based Rate Authority

The traditional electric operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and Southern Power filed a triennial market power analysis in ~~June~~ 2014, which included continued reliance on the energy auction as tailored mitigation. ~~On April 27,~~In 2015, the FERC issued an order finding that the traditional electric operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power filed a request for rehearing ~~on May 27, 2015~~ and ~~on June 26, 2015~~ filed their response with the ~~FERC.~~ FERC in 2015.

In December 2016, the traditional electric operating companies and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.

The ultimate outcome of ~~this matter~~these matters cannot be determined at this time.

~~Retail~~ Southern Company Gas

At December 31, 2017, Southern Company Gas' midstream operations business was involved in two gas pipeline construction projects, the Atlantic Coast Pipeline project and the PennEast Pipeline project, which received FERC approval in October 2017 and January 2018, respectively. Southern Company Gas' portion of the expected capital expenditures for these projects total approximately $586 million. These projects, along with Southern Company Gas' existing pipelines, are intended to provide diverse sources of natural gas supplies to customers, resolve current and long-term supply planning for new capacity, enhance system reliability, and generate economic development in the areas served.

On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced. See Note 4 to the financial statements for additional information.

Regulatory Matters

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. See Note 3 to the financial statements under ~~"Retail~~ "Regulatory Matters – Alabama ~~Power"~~Power" for additional information regarding Alabama Power's rate mechanisms and accounting orders.

Rate RSE

At December 31, 2016, Alabama Power's retail return exceeded the allowed WCE range which resulted in Alabama Power establishing a $73 million Rate RSE refund liability. In accordance with an Alabama PSC order issued on February 14, 2017, Alabama Power applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below.

Effective in January 2017, Rate RSE increased 4.48%, or $245 million annually. At December 31, 2017, Alabama Power's actual retail return was within the allowed WCE range. On ~~November 30, 2015,~~December 1, 2017, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for ~~2016.~~calendar year 2018. Projected earnings were within the specified ~~WCE~~ range; therefore, retail rates under Rate RSE remained unchanged for ~~2016.~~2018.

In conjunction with Rate RSE, Alabama Power has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time.

Rate CNP PPA

~~II-28~~

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

~~Rate CNP PPA. On March 3, 2015, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate~~ CNP PPA factor for billings for the period April 1, ~~2015~~2017 through March 31, ~~2016.~~2018. No adjustment to Rate CNP PPA is expected in ~~2016.~~2018.

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power eliminated the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," Alabama Power utilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2017.

Rate CNP ~~Environmental allowed~~Compliance

Rate CNP Compliance allows for the recovery of Alabama Power's retail costs associated with ~~environmental~~ laws, regulations, and other such mandates. On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power was limited to recover $50 million of non-environmental compliance costs for the year 2015. Additional non-environmental compliance costs were recovered through Rate RSE. Customer rates were not impacted by this order in 2015; therefore, the modification increased the under recovered position for Rate CNP Compliance during 2015. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital.

~~On November 30, 2015, Alabama Power made its annual~~ Revenues for Rate CNP Compliance, ~~submission to~~as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its ~~cost of complying with governmental mandates for cost year 2016.~~under recovered balance in Rate CNP Compliance ~~increased 4.5%, or approximately $250 million annually,~~to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, ~~2016.~~2017.

Environmental Accounting Order

Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. ~~These costs are being~~The regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance. See ~~"Environmental~~"Environmental Matters – Environmental ~~Statutes~~Laws and ~~Regulations"~~Regulations" herein for additional information regarding environmental regulations.

In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7 (200 MWs). Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. In accordance with the joint stipulation entered in connection with a civil enforcement action by the EPA, Alabama Power retired Plant Barry Unit 3 (225 MWs) in August 2015 and it is no longer available for generation. Alabama Power expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas by April 2016.

In accordance with this accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized and recovered through Rate CNP Compliance over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Southern Company's financial statements.

~~Cost of Removal Accounting Order~~

In accordance with an accounting order issued in November 2014 by the Alabama PSC, in December 2014, Alabama Power fully amortized the balance of $123 million in certain regulatory asset accounts and offset this amortization expense with the amortization of $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset accounts fully amortized and terminated as of December 31, 2014 represented costs previously deferred under a compliance and pension cost accounting order as well as a non-nuclear outage accounting order, which were approved by the Alabama PSC in 2012 and 2013, respectively. Approximately $95 million of non-nuclear outage costs and $28 million of compliance and pension costs previously deferred were fully amortized in December 2014.

Georgia Power

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 (DSM) tariffs, Environmental Compliance Cost Recovery (ECCR) tariffs, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs on certified project costs related to the construction 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 ~~tariffs.~~tariff. See Note 3 to the financial statements under ~~"Retail~~ "Regulatory Matters – Georgia ~~Power"~~Power" for additional information.

Rate Plans

~~II-29~~Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC in April 2016, the 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60/40 basis with their respective customers; thereafter, all merger savings will be retained by customers. See Note 3 to the financial

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

statements under "Regulatory Matters – Georgia Power – Rate Plans

~~In 2013, the Georgia PSC voted to approve~~" for additional information regarding the 2013 ~~ARP. The 2013~~ ARP ~~reflects~~and Note 12 to the ~~settlement agreement among Georgia Power,~~financial statements under "Southern Company – Merger with Southern Company Gas" for additional information regarding the ~~Georgia PSC's Public Interest Advocacy Staff, and 11 of the 13 intervenors.~~Merger.

~~On December 16, 2015, in~~In accordance with the 2013 ARP, the Georgia PSC approved ~~an increase~~increases to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately $49 million; (2) ECCR tariff by approximately $75 million; (3) DSM tariffs by approximately $3 million; and (4) MFF tariff by approximately $13 million, for a total increase in base revenues of approximately $140 million. There were no changes to these tariffs in 2017.

Under the 2013 ARP, Georgia Power's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In ~~2014,~~2015, Georgia Power's retail ROE was within the allowed retail ROE range. In 2016, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power will refund to retail customers approximately ~~$11~~$44 million in ~~2016,~~2018, as approved by the Georgia PSC on ~~February 18, 2016.~~January 16, 2018. In ~~2015,~~2017, Georgia Power's retail ROE was within the allowed retail ROE ~~range.~~range, subject to review and approval by the Georgia PSC.

On January 19, 2018, the Georgia PSC issued an order on the Tax Reform Legislation, which was amended on February 16, 2018 (Tax Order). In accordance with the Tax Order, Georgia Power is required to ~~file a general base rate case~~submit its analysis of the Tax Reform Legislation and related recommendations to address the related impacts on Georgia Power's cost of service and annual revenue requirements by ~~July 1, 2016, in response to which the Georgia PSC would~~March 6, 2018. The ultimate outcome of this matter cannot be ~~expected to determine whether the 2013 ARP should be continued, modified, or discontinued.~~determined at this time.

Integrated Resource Plan

See ~~"Environmental Matters" and "Rate Plans"~~"Environmental Matters" herein for additional information regarding proposed and final EPA rules and regulations, including ~~the MATS rule for coal- and oil-fired electric utility steam generating units,~~ revisions to ~~effluent limitations guidelines~~ELG for steam electric power plants and additional regulations of CCR and CO₂; the State of Georgia's Multi-Pollutant Rule; and Georgia Power's analysis of the potential costs and benefits of installing the required controls on its fossil generating units in light of these regulations..

To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired and operations were discontinued at Plant Mitchell Unit 3 (155 MWs) by April 15, 2015, and Plant Kraft Units 1 through 4 (316 MWs) were retired on October 13, 2015. The switch to natural gas as the primary fuel was completed at Plant Yates Units 6 and 7 by June 2015 and at Plant Gaston Units 1 through 4 by December 2015.

In ~~the 2013 ARP,~~July 2016, the Georgia PSC approved the amortization of the CWIP balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 over nine years ending December 2022 and the amortization of the remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024.

~~On January 29, 2016,~~ Georgia ~~Power filed its~~Power's triennial ~~IRP~~Integrated Resource Plan (2016 IRP)~~. The filing included a request to decertify~~ including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs) ~~upon approval~~, as well as the decertification of the Intercession City unit (143 MWs total capacity). In August 2016, ~~IRP. The 2016 IRP also reflects that~~the Plant Mitchell and Plant Kraft units were retired and Georgia Power ~~exercised its contractual option to sell~~sold its 33% ownership interest in the Intercession City unit ~~(143 MWs total capacity)~~ to Duke Energy Florida, ~~Inc. See Note 4 to~~LLC.

Additionally, the ~~financial statements for additional information.~~

InGeorgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.

The decertification and retirement of these units are not expected to have a material impact on Southern Company's financial statements; however, the ultimate outcome depends on the Georgia PSC's ordersunit's net book value will continue through December 31, 2019, as provided in the ~~2016 IRP~~2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and ~~next general~~costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in Georgia Power's 2019 base rate case.

~~Additionally,~~The Georgia PSC also approved the ~~2016 IRP included a~~ Renewable Energy Development Initiative ~~requesting~~(REDI) to procure ~~up to 525~~an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.

In 2017, Georgia Power filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to ~~expand~~be in operation by the end of 2019. Georgia ~~Power's existing renewable initiatives, including~~Power also filed for and received approval to develop several solar generation projects to fulfill the ~~Advanced Solar Initiative (ASI).~~approved self-build capacity.

~~A decision from~~In the 2016 IRP, the Georgia PSC onalso approved 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. On March 7, 2017, the ~~2016 IRP~~Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC in a future Georgia Power rate case.

Storm Damage Recovery

Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the ~~third quarter 2016.~~2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. Hurricanes Irma and Matthew caused significant damage to Georgia Power's transmission and distribution facilities during September 2017 and October 2016, respectively. The ~~ultimate outcome of~~incremental restoration costs related to these ~~matters cannot be determined at this time.~~hurricanes deferred in Georgia Power's regulatory

~~II-30~~

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

~~Renewables~~

~~On September 16, 2015,~~asset for storm damage totaled approximately $260 million. At December 31, 2017, the Alabama PSC approved Alabama Power's petition for a Renewable Generation Certificate for up to 500 MWs. This will allow Alabama Power to build its own renewable projects, each less than 80 MWs, or purchase power from other renewable-generated sources.

~~In May 2014, the Georgia PSC approved~~total balance in Georgia Power's ~~application for the certification~~regulatory asset related to storm damage was $333 million. The rate of ~~two PPAs executed in 2013 for the purchase of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will begin in 2016 and end in 2035.~~

Asstorm damage cost recovery is expected to be adjusted as part of ~~the~~ Georgia ~~Power ASI, Georgia Power executed ten PPAs that were approved~~Power's next base rate case required to be filed by the Georgia PSC in 2014 and provide for the purchase of energy from 515 MWs of solar capacity. Two PPAs began in December 2015 and eight are expected to begin in December 2016, all of which have terms ranging from 20 to 30 years.July 1, 2019. As a result of ~~certain acquisitions by~~this regulatory treatment, costs related to storms are not expected to have a material impact on Southern ~~Power,~~ Company's financial statements. See Note 3 to the financial statements under "Regulatory Matters – Georgia Power ~~expects that 249 MWs of the 515 MWs of contracted capacity will be purchased from solar facilities owned or under development by Southern Power.~~

~~In October 2014, the Georgia PSC approved~~ – Storm Damage Recovery" for additional information regarding Georgia Power's request to build, own, and operate three 30-MW solar generation facilities at three U.S. Army bases by the end of 2016. One of the three solar generation facilities began commercial operation on December 31, 2015. In addition, in December 2014, the Georgia PSC approved Georgia Power's request to build, own, and operate a 30-MW solar generation facility at Kings Bay Naval facility. On July 21, 2015, the Georgia PSC approved Georgia Power's request to build and operate an up to 46-MW solar generation facility at a U.S. Marine Corps base in Albany, Georgia. Georgiastorm damage reserve.

Gulf Power subsequently determined that a 31-MW facility will be constructed on the site. On December 22, 2015, the Georgia PSC approved Georgia Power's request to build and operate the remaining 15 MWs at a separate facility on the Fort Stewart Army base in Hinesville, Georgia. These facilities are expected to be operational by the end of 2016.

On April ~~7, 2015,~~4, 2017, the ~~Georgia~~Florida PSC approved the ~~consolidation~~2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request in 2016 to increase retail base rates. Among the terms of ~~four PPAs each~~the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the ~~same counterparty into two~~first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes. Gulf Power also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new ~~PPAs~~depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with ~~new biomass facilities.~~the ongoing ownership and operation of the unit through the environmental cost recovery clause.

The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to Gulf Power's base rates. Under the terms of the ~~order,~~2017 Rate Case Settlement Agreement, by March 1, 2018, Gulf Power must identify the ~~total 116 MWs from the existing four PPAs provided the capacity~~revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for ~~two new PPAs of 58 MWs each. The new PPAs were executed on June 15, 2015 and November 23, 2015 and will begin~~prospective application in ~~June 2017. See "Retail Regulatory Matters – Georgia Power – Integrated Resource Plan" herein for additional information on Georgia Power's renewables activities.~~

~~On April 16, 2015,~~a change to base rates in a limited scope proceeding before the Florida ~~PSC approved three energy purchase agreements totaling 120 MWs~~PSC. In lieu of ~~utility-scale solar generation located at three military installations in northwest Florida. Purchases under these solar agreements are expected~~this approach, on February 14, 2018, the parties to ~~begin by early 2017. On May 5, 2015,~~the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida ~~PSC~~PSC. If approved, ~~an energy purchase agreement~~the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to Gulf Power's base rates and $15.6 million to Gulf Power's environmental cost recovery rates effective beginning the first calendar month following approval.

The 2018 Tax Reform Settlement Agreement also provides for upa one-time refund of $69.4 million for the retail portion of unprotected (not subject to ~~178 MWs of wind generation in central Oklahoma. Purchases under these agreements began in January 2016, are for energy only, and will be recovered~~normalization) deferred tax liabilities through Gulf Power's fuel cost recovery ~~mechanism.~~rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and Gulf Power will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.

If the 2018 Tax Reform Settlement Agreement is approved, the 2017 Rate Case Settlement Agreement will be amended to increase Gulf Power's maximum equity ratio from 52.5% to 53.5% for regulatory purposes.

The ultimate outcome of these matters cannot be determined at this time.

Mississippi Power

On ~~November 10, 2015, the Mississippi PSC issued three separate orders approving three solar facilities for a combined total of approximately 105 MWs.~~February 7, 2018, Mississippi Power ~~will purchase all~~revised its annual projected PEP filing for 2018 to reflect the impacts of the ~~energy produced~~Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%. The ultimate outcome of this matter cannot be determined at this time.

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. These agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE.

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

distribution services by charging rates to its customers based primarily on monthly fixed charges that are set by the ~~solar facilities~~Georgia PSC and adjusted periodically.

With the exception of Atlanta Gas Light, 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 ~~25-year term~~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 and energy efficiency plans. See Note 1 to the financial statements under "Cost of Natural Gas" for additional information.

Regulatory Infrastructure Programs

Certain of Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs are designed to update or expand the natural gas distribution systems of the ~~contracts~~natural gas distribution utilities to improve reliability and meet operational flexibility and growth. Initial program lengths range from nine to 10 years, with completion dates ranging from 2020 through 2025. The total expected investment under ~~three PPAs, two~~these programs for 2018 is $395 million.

Base Rate Cases

On January 31, 2018, the Illinois Commerce Commission approved a $137 million increase in Nicor Gas' annual base rate revenues, including $93 million related to the recovery of investments under Nicor Gas' infrastructure program, effective February 8, 2018, based on a ROE of 9.8%.

The Illinois Commerce Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commerce Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which ~~have been finalized and one of which remains under negotiation. The projects are expected~~Nicor Gas expects to ~~be in service~~file by the end of ~~2016 and~~ the ~~resulting energy purchases~~second quarter 2018.

On December 1, 2017, Atlanta Gas Light filed its 2018 annual rate adjustment with the Georgia PSC. If approved, Atlanta Gas Light's annual base rate revenues will increase by $22 million, effective June 1, 2018. Atlanta Gas Light will file a revised rate adjustment to incorporate the effects of the Tax Reform Legislation in the first quarter 2018. The Georgia PSC is expected to rule on the revised requested increase in the second quarter 2018.

The ultimate outcome of these matters cannot be ~~recovered through Mississippi Power's fuel cost recovery mechanism.~~determined at this time.

~~See Note 12 to the financial statements for information on Southern Power's renewables activities.~~

~~Retail~~ Fuel Cost Recovery

The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary. During 2015, each of the traditional operating companies filed requests with their respective state PSCs for fuel rate decreases. Upon approval of these requests, each of the traditional operating companies decreased fuel rates in January 2016.

See Note 1 to the financial statements under ~~"Revenues"~~"Revenues" and Note 3 to the financial statements under ~~"Retail~~ "Regulatory Matters – Alabama Power – Rate ~~ECR"~~ECR" and ~~"Retail~~ "Regulatory Matters – Georgia Power – Fuel Cost ~~Recovery"~~Recovery" for additional information.

Kemper County Energy Facility

~~II-31~~The Kemper County energy facility was approved by the Mississippi PSC as an IGCC facility in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of the Initial DOE Grants and excluding the Cost Cap Exceptions. The combined cycle and associated common facilities portions of the Kemper County energy facility were placed in service in August 2014. In December 2015, the Mississippi PSC issued the In-Service Asset Rate Order, authorizing rates that provided for the recovery of approximately $126 million annually related to the assets previously placed in service.

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Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility. The Kemper Settlement Order established the Kemper Settlement Docket for the purposes of pursuing a global settlement of the related costs.

On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. At the time of project suspension, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants. In the aggregate, Mississippi Power had incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine.

On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors. The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6%, excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).

As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.

See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.

Litigation

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the

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Southern Company and Subsidiary Companies 2017 Annual Report

plaintiffs filed notice of an appeal. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company intends to vigorously defend itself in this matter and the ultimate outcome of this matter cannot be determined at this time.

On June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint related to the cancelled CO₂contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and sought compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO₂ contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop and other related parties filed a claim for arbitration requesting $500 million in damages. On December 28, 2017, Mississippi Power reached a settlement agreement with Treetop and other related parties and the arbitration was dismissed.

Construction Program

Overview

The subsidiary companies of Southern Company 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, ~~as well as~~ adding ~~or changing fuel sources for~~environmental modifications to certain existing units, ~~adding environmental control equipment,~~expanding the electric transmission and distribution systems, and updating and expanding the ~~transmission and~~natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. ~~The construction~~Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the ~~traditional operating companies~~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 their regulated rates. The Southern ~~Power are~~Company system's construction program is currently estimated to ~~include an investment of~~total approximately ~~$7.3~~$9.4 billion, ~~$5.2~~$9.3 billion, $8.4 billion, $7.0 billion, and ~~$5.5~~$6.9 billion for ~~2016, 2017,~~2018, 2019, 2020, 2021, and ~~2018,~~2022, respectively.

The ~~two~~ largest construction ~~projects~~project currently underway in the Southern Company system ~~are~~is Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs) ~~and Mississippi Power's Kemper IGCC.~~. See Note 3 to the financial statements under ~~"Retail Regulatory Matters – Georgia Power –~~ "Nuclear ~~Construction" and "Integrated Coal Gasification Combined Cycle"~~Construction" for additional information. ~~For~~See Note 12 to the financial statements under "Southern Power" for additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy ~~facilities, see~~facilities. See Note 123 to the financial statements under ~~"Southern Power~~"Regulatory Matters – ~~Construction Projects.~~Southern Company Gas – Regulatory Infrastructure Programs" for additional information regarding infrastructure improvement programs at the natural gas distribution utilities.

Also see FINANCIAL CONDITION AND LIQUIDITY – ~~"Capital~~"Capital Requirements and Contractual ~~Obligations"~~Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.

~~Integrated Coal Gasification Combined Cycle~~Nuclear Construction

~~Mississippi Power's current cost estimate~~Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy

In 2008, Georgia Power, acting for itself and as agent for the ~~Kemper IGCC~~Vogtle Owners, entered into the Vogtle 3 and 4 Agreement. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In the first quarter 2016, Westinghouse delivered to the Vogtle Owners a total of $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement.

Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against the EPC Contractor

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Southern Company and Subsidiary Companies 2017 Annual Report

and the Vogtle Owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of December 31, 2017.

On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share was approximately $1.7 billion. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in ~~total~~October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, Georgia Power, the other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of Georgia Power, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and Georgia Power and the other Vogtle Owners surrendered the Westinghouse Letters of Credit.

Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement, which was amended and restated on July 20, 2017. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Vogtle Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Vogtle Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Vogtle Services Agreement 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.

Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be 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. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.

On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, 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 (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power 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 because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. 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.

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Southern Company and Subsidiary Companies 2017 Annual Report

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 nuclear construction projects certified by the Georgia PSC. 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. As of December 31, 2017, Georgia Power had recovered approximately ~~$6.63~~$1.6 billion ~~which includes~~of financing costs. On January 30, 2018, Georgia Power filed to decrease the NCCR tariff by approximately ~~$5.29~~$50 million, effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, the Customer Refunds ordered by the Georgia PSC aggregating approximately $188 million, and the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and will be paid in three installments of $25 to each retail customer no later than the third quarter 2018.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. In October 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation (2013 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.

~~During 2015, events related~~prudent and none of the amounts paid pursuant to the ~~Kemper IGCC had~~Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.680 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 $5.680 billion were prudent, and (c) a ~~significant adverse~~revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) is 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 ~~Mississippi Power's financial condition. These events include (i)~~cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ~~termination~~ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by ~~SMEPA in May 2015 of~~ the ~~APA between Mississippi Power and SMEPA, whereby SMEPA previously agreed to purchase a 15% undivided interest~~Georgia PSC in the ~~Kemper IGCC,~~2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and ~~Mississippi~~(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 ~~subsequent return~~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 $20 million in 2016 and $25 million in 2017 and are estimated to have negative earnings impacts of approximately ~~$301 million, including interest, to SMEPA; (ii) the termination of Mirror CWIP rates in July 2015 and the refund of $371~~$120 million in ~~Mirror CWIP rate collections, including carrying costs, in~~2018 and an aggregate of $585 million from 2019 to 2022. In its January 11, 2018 order, the ~~fourth quarter 2015 as a result of the Mississippi Supreme Court's reversal of the Mississippi PSC's 2013 rate order authorizing the collection of $156 million annually in Mirror CWIP rates;~~Georgia PSC stated if other certain conditions and (iii) the required recapture in December 2015 of $235 million of Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 48A (Phase II) tax credits as a result of the extension of the expected in-service date for the Kemper IGCC.

As a result of the termination of the Mirror CWIP rates, Mississippi Power submitted a filing to the Mississippi PSC requesting interim rates to collect approximately $159 million annually until a final rate decision could be made on Mississippiassumptions upon which Georgia Power's request to recover costs associated with Kemper IGCC assets that had been placed in service. The Mississippi PSC approved the implementation of the requested interim rates in August 2015. Subsequently, on December 3, 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order),seventeenth VCM report are based ~~on a stipulation between Mississippi~~do not materialize, both Georgia Power and the ~~MPUS, authorizing Mississippi Power~~Georgia PSC reserve the right to ~~replace~~reconsider the ~~interim rates with rates that provide for the recovery of approximately $126 million annually related~~decision to Kemper IGCC assets previously placed in service. Further proceedings related to cost recovery for the Kemper IGCC are expected after the remainder of the Kemper IGCC is placed in service, which is currently expected in the third quarter 2016. continue construction.

On February ~~25, 2016, Greenleaf CO2 Solutions, LLC~~12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a ~~notice of appeal of~~petition appealing the ~~In-Service Asset Rate Order~~Georgia PSC's January 11, 2018 order with the ~~Mississippi Supreme~~Fulton County Superior Court. ~~Mississippi~~Georgia Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of ~~operations.~~operations, financial condition, and liquidity.

The ~~ultimate outcome~~IRS allocated PTCs to each of ~~these matters cannot~~Plant Vogtle Units 3 and 4, which originally required the applicable unit to be ~~determined at this time.~~placed in service before 2021. Under the Bipartisan Budget Act of 2018, Plant Vogtle Units 3 and 4 continue to qualify for PTCs. The nominal value of Georgia Power's portion of the PTCs is approximately $500 million per unit.

~~II-32~~

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Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

~~Nuclear Construction~~

~~On December 31, 2015, Westinghouse Electric Company LLC (Westinghouse) and~~In its January 11, 2018 order, the Georgia PSC also approved $542 million of capital costs incurred during the seventeenth VCM reporting period (January 1, 2017 to June 30, 2017). The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. Georgia Power ~~Oglethorpe Power Corporation, the Municipal Electric Authority~~expects to file its eighteenth VCM report on February 28, 2018 requesting approval of ~~Georgia, and the City~~approximately $450 million of Dalton, Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, Vogtle Owners), entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and Westinghouse and Stone & Webster, Inc., a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. (CB&I) (Westinghouse and Stone & Webster, Inc., collectively, Contractor)construction capital costs (before payments received under the engineering, procurement, and construction agreement between the Vogtle Owners and the Contractor (Vogtle 3 and 4 Agreement), including the pending litigation between the Vogtle Owners and the Contractor (Vogtle Construction Litigation).

Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The ContractorGuarantee Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will now commenceCustomer Refunds) incurred from ~~the current estimated nuclear fuel loading date for each unit, which is~~July 1, 2017 through December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4, rather than the original guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $120 million has been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. Further, subsequent to December 31, 2015, Georgia Power paid approximately $121 million under the terms of the Contractor Settlement Agreement. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in2017. Georgia Power's ~~previously disclosed in-service cost estimate.~~

Further, as part of the settlement: (i) Westinghouse has engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. have entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction ofCWIP balance for Plant Vogtle Units 3 and 4 ~~that occurred on~~was approximately $4.8 billion as of December 31, 2017, or ~~before~~$3.3 billion net of payments received under the ~~date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.~~

~~On January 21, 2016, Georgia Power submitted the Contractor~~Guarantee Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. On February 2, 2016, the Georgia PSC ordered Georgia Power to file supplemental information by April 5, 2016 in support of the Contractor Settlement Agreement and Georgia Power's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable. Following Georgia Power's filing under the order, the Georgia PSC Staff (Staff) will conduct a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement and the Staff is authorized to engage in related settlement discussions with Georgia Power and any intervenors. The order provides that the Staff is required to report to the Georgia PSC by October 5, 2016 with respect to the status of its review and any settlement-related negotiations.Customer Refunds.

The ultimate outcome of these matters cannot be determined at this time.

~~Income Tax Matters~~Cost and Schedule

~~Bonus Depreciation~~

~~On December 18, 2015,~~Georgia Power's approximate proportionate share of the ~~Protecting Americans from Tax Hikes (PATH) Act was signed into law. Bonus depreciation was extended for qualified property placed~~remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service ~~over~~dates of November 2021 and November 2022, respectively, is as follows:



	(in billions)
Project capital cost forecast	$	7.3
Net investment as of December 31, 2017	(3.4		)
Remaining estimate to complete	$	3.9

Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the ~~next five years. The PATH Act allows~~Guarantee Settlement Agreement and the Customer Refunds.

Georgia Power estimates that its financing costs for ~~50% bonus depreciation for 2015, 2016,~~construction of Plant Vogtle Units 3 and ~~2017; 40% bonus depreciation for 2018;~~4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.

As construction continues, challenges with management of contractors, subcontractors, and ~~30% bonus depreciation for 2019~~vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new technology and have not yet operated in the global nuclear industry at this scale), or other issues could arise and change the projected schedule and estimated cost.

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 ~~long-lived assets placed in service in 2020. The extension~~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 resolution of ~~50% bonus depreciation is expected to~~Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, which may result in ~~approximately $855 million of positive cash flows for~~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 ~~2015 tax year and approximately $1.3 billion for the 2016 tax year, which may not all be realized~~project schedule that could result in 2016 due to a projected net operating loss for the 2016 tax year. Approximately $360 million of this benefit is dependent upon placing the remainder of the Kemper IGCC in service in 2016. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information. increased costs.

The ultimate outcome of ~~this matter~~these matters cannot be determined at this time.

Other Matters

~~II-33~~As of December 31, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

The ultimate outcome of these matters cannot be determined at this time.

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Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

Income Tax Matters

Federal Tax Reform Legislation

On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduces the federal corporate income tax rate to 21%, retains normalization provisions for public utility property and existing renewable energy incentives, and repeals the corporate alternative minimum tax.

For businesses other than regulated utilities, the Tax Reform Legislation allows 100% bonus depreciation of qualified property acquired and placed in service between September 28, 2017 and January 1, 2023 and phases down by 20% each year until completely phased out for qualified property placed in service after December 31, 2027. Further, the business interest deduction is limited to 30% of taxable income excluding interest, net operating loss (NOL) carryforwards, and depreciation and amortization through December 31, 2021, and thereafter to 30% of taxable income excluding interest and NOL carryforwards.

Regulated utility businesses, including the majority of the operations of the traditional electric operating companies and the natural gas distribution companies, can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. Projects with binding contracts before September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the Protecting Americans from Tax Hikes (PATH) Act.

In addition, under the Tax Reform Legislation, NOLs generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the subsequent tax year. The projected reduction of the consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards.

For the year ended December 31, 2017, implementation of the Tax Reform Legislation resulted in an estimated net tax benefit of $264 million, a $0.4 billion decrease in regulatory assets, and a $6.9 billion increase in regulatory liabilities, primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities. Also, the OCI ending balance at December 31, 2017 includes $30 million of stranded excess deferred tax balances, which will be adjusted through retained earnings in subsequent periods.

The Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and relevant state regulatory bodies. On January 31, 2018, SCS, on behalf of the traditional electric operating companies, filed with the FERC a reduction to the open access transmission tariff charge for 2018 to reflect the revised federal corporate income tax rate. See Note 3 to the financial statements under "Regulatory Matters" for additional information regarding the traditional electric operating companies' and the natural gas distribution utilities' rate filings to reflect the impacts of the Tax Reform Legislation.

On February 9, 2018, the Bipartisan Budget Act of 2018 was signed into law. Included in the tax extenders portion of the law were provisions extending PTCs on advanced nuclear power facilities and ITCs on qualified fuel cells. A subsidiary of PowerSecure installed fuel cells in 2017 which are expected to qualify for approximately $80 million of ITCs; however, the impact of the related tax benefits would be substantially offset by additional required payments under the applicable purchase contracts. Should Southern Company have a NOL in 2018, all of these ITCs may not be fully realized in 2018. See Note 3 to the financial statements under "Nuclear Construction" for additional information on the PTCs relating to advanced nuclear power facilities.

See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.

The ultimate outcome of these matters cannot be determined at this time.

Bonus Depreciation

Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, bonus depreciation is expected to result in positive cash flows of approximately $870 million for the 2017 tax year and approximately $290 million for the 2018 tax year. Should Southern Company have a NOL in 2018, all of these cash flows may not be fully realized in 2018. All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. Additionally, Southern Company will record an abandonment loss on its 2018 corporate income tax return, which may

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Southern Company and Subsidiary Companies 2017 Annual Report

not be fully realized should Southern Company have a NOL in 2018. See Notes 3 and 5 to the financial statements under "Kemper County Energy Facility" and "Current and Deferred Income Taxes – Net Operating Loss," respectively, for additional information. The ultimate outcome of these matters cannot be determined at this time.

Tax Credits

The ~~IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with~~Tax Reform Legislation retained the ~~Kemper IGCC. These tax credits~~renewable energy incentives that were ~~dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO~~₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. As a result of the schedule extension for the Kemper IGCC, the Phase II credits have been recaptured. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information.

~~In 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives~~included in the ~~ARRA included renewable energy incentives.~~PATH Act. The PATH Act ~~extended the ITC with a phase out that~~ allows for 30% ITC for solar projects that commence construction by December 31, 2019; 26% ITC for solar projects that commence construction in 2020; 22% ITC for solar projects that commence construction in 2021; and ~~the~~a permanent 10% ITC for solar projects that commence construction on or after January 1, 2022. In addition, the PATH Act ~~extended the production tax credit (PTC) for wind projects with a phase out that~~ allows for 100% PTC for wind projects that ~~commence~~commenced construction in 2016; 80% PTC for wind projects that ~~commence~~commenced construction in 2017; 60% PTC for wind projects that commence construction in 2018; and 40% PTC for wind projects that commence construction in 2019. Wind projects commencing construction after 2019 will not be entitled to any PTCs. The Company has received ITCs and PTCs in connection with investments in solar, wind, and biomass facilities primarily at Southern Power and Georgia Power. See Note 1 to the financial statements under "Income and Other Taxes" and Note 5 to the financial statements under "Current and Deferred Income Taxes – Tax Credit Carryforwards" for additional information regarding the utilization and amortization of credits ~~amortized~~ and the tax benefit related to basis differences.

~~Section 174 Research~~Southern Power

In September 2017, Southern Power began a legal entity reorganization of various direct and ~~Experimental Deduction~~

~~Southern Company reflected deductions for research~~indirect subsidiaries that own and ~~experimental (R&E) expenditures~~operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $55 million related to certain changes in state apportionment rates and net operating loss carryforward utilization that will be recorded in the ~~Kemper IGCC~~first quarter 2018. Southern Power is pursuing the sale of a 33% equity interest in its federal income tax calculations for 2013, 2014, and 2015. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the ~~uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with~~newly-formed holding company owning these R&E deductions totaling approximately $423 million as of December 31, 2015. See Note 5 to the financial statements under "Unrecognized Tax Benefits" for additional information. Also see "Bonus Depreciation" herein.solar assets. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. 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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as standards for air, ~~quality~~water, land, and ~~water standards,~~protection of other natural resources, 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 ~~against Southern Company and its subsidiaries~~or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

~~Through 2015, capacity revenues represented~~In 2016, the ~~majority~~SEC began conducting a formal investigation of ~~Gulf Power's wholesale earnings. Gulf~~Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper County energy facility. On November 30, 2017, the SEC staff notified Southern Company that it had ~~long-term sales contracts to cover 100%~~concluded its investigation with no recommended enforcement action.

Litigation

On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its ~~ownership share of Plant Scherer Unit 3 (205 MWs)~~officers, and ~~these capacity revenues represented 82% of Gulf Power's total wholesale capacity revenues for 2015. Due to~~certain former Mississippi Power officers in the ~~expiration of a wholesale contract at the end of 2015 and future expiration dates of the remaining wholesale contracts~~U.S. District Court for the ~~unit, Gulf Power currently has contracts to cover 34%~~Northern District of ~~the unit for 2016 and 27%~~Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of ~~the unit through 2019. Gulf Power is actively evaluating alternatives relating to this asset, including replacement wholesale contracts. The expiration~~all persons who purchased shares of ~~the contract in 2015 and the scheduled future expiration of the remaining contracts are not expected to have a material impact on~~ Southern Company's earnings. In the event some portion of the Gulf Power's ownership of Plant Scherer Unit 3 is not subject to a replacement long-term wholesale contract, the proportionate amount of the unit may be sold into thecommon stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, ~~power pool or into~~certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the ~~wholesale market.~~Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The ~~ultimate outcome of this matter cannot be determined at this time.~~complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 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

~~II-34~~

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other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.

On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.

On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov 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 officers, and certain former Mississippi Power officers. Each 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. Each 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. Each 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. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.

Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.

Investments in Leveraged Leases

A subsidiary of Southern Holdings has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. See Note 1 to the financial statements under "Leveraged Leases" for additional information.

The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. In the last six months of 2017, the financial and operational performance of one of the lessees and the associated generation assets has raised significant concerns about the short-term ability of the generation assets to produce cash flows sufficient to support ongoing operations and the lessee's contractual obligations and its ability to make the remaining semi-annual lease payments to the Southern Holdings subsidiary beginning in June 2018. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If the June 2018 (or any future) lease payment 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 would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable which had a balance of approximately $86 million as of December 31, 2017. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of December 31, 2017. 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, including the lease payment due in June 2018. The ultimate outcome of this matter cannot be determined at this time.

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Southern Company and Subsidiary Companies 2017 Annual Report

Natural Gas Storage

A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At December 31, 2017, the facility's property, plant, and equipment had a net book value of $112 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.

The cavern continues to maintain its pressures and overall structural integrity. Southern Company Gas intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with Southern Company Gas' annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements.

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 Note 1 to the financial statements. 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. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.

~~Electric~~ Utility Regulation

Southern Company's traditional electric operating companies and natural gas distribution utilities, which collectively comprised approximately ~~94%~~86% of Southern Company's total operating revenues for ~~2015,~~2017, are subject to retail regulation by their respective state PSCs or other applicable state regulatory agencies and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional electric operating companies and the natural gas distribution utilities are permitted to charge customers based on allowable costs, including a reasonable ROE. As a result, the traditional electric operating companies and the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional electric operating ~~companies;~~companies and the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.

As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.

Kemper ~~IGCC Estimated Construction Costs, Project Completion Date, and~~County Energy Facility Rate Recovery

~~During 2015,~~For periods prior to the second quarter 2017, significant accounting estimates included Kemper County energy facility estimated construction costs, project completion date, and rate recovery. Mississippi Power further revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions.

~~As a result of the revisions to the cost estimate, Southern Company~~ recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, and $540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.4 billion ($1.5 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through December 31, 2015.related

Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

~~II-35~~

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Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

~~Mississippi Power's revised cost estimate includes costs through August 31, 2016. Any extension~~to the Kemper County energy facility of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.

As a result of the ~~in-service date beyond August 31, 2016 is currently estimated~~Mississippi PSC's June 21, 2017 stated intent to ~~result in additional base costs of approximately $25 million~~issue an order (which occurred on July 6, 2017) directing Mississippi Power to ~~$35 million per month,~~pursue a settlement under which ~~includes maintaining necessary levels of start-up labor, materials, and fuel,~~the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extensionMississippi Power's June 28, 2017 suspension of the ~~in-service date with respect to~~operation and start-up of the gasifier portion of the Kemper ~~IGCC beyond August 31, 2016 would also~~County energy facility, the estimated construction costs and project completion date are no longer considered significant accounting estimates.

Given the Mississippi PSC's stated intent regarding no further rate increase ~~costs~~ for the ~~Cost Cap Exceptions,~~Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which ~~are not subject~~included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the ~~$2.88 billion cost cap established by~~suspension period prior to conclusion of the ~~Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month,~~Kemper Settlement Docket, as well as ~~carrying costs~~a charge of $78 million associated with the Kemper Settlement Agreement.

In the aggregate, since the Kemper County energy facility project started, Mississippi Power has incurred charges of $6.20 billion ($4.14 billion after tax) through December 31, 2017. See Note 14 to the financial statements for additional information on the individual charges by quarter.

As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges, and ~~operating expenses~~no longer represents a critical accounting estimate.

See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.

Accounting for Income Taxes

The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in which the Southern Company system operates.

Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on ~~Kemper IGCC~~a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of the Company's current financial position and result of operations, including currently available information about future years, to estimate when future taxable income will be realized.

Current and deferred state income tax liabilities and assets ~~placed~~are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States utilize various formulas to calculate the apportionment of taxable income, primarily using sales, assets, or payroll within the jurisdiction compared to the consolidated totals. In addition, each state varies as to whether a stand-alone, combined, or unitary filing methodology is required. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in ~~service~~future years. The apportionments and ~~consulting and legal fees of approximately $2 million per month.~~methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on Southern Company's financial statements.

Given the significant judgment involved in estimating ~~the future costs to complete construction~~NOL and ~~start-up, the project completion date, the ultimate rate recovery~~tax credit carryforwards and multi-state apportionments for ~~the Kemper IGCC, and the potential impact on Southern Company's results of operations,~~all subsidiaries, Southern Company considers ~~these items~~state deferred income tax liabilities and assets to be critical accounting estimates.

Federal Tax Reform Legislation

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Southern Company and Subsidiary Companies 2017 Annual Report

to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See ~~Note~~FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under ~~"Integrated Coal Gasification Combined Cycle"~~"Regulatory Matters" and "Current and Deferred Income Taxes," respectively, for additional information.

Asset Retirement Obligations

AROs are computed as the fair value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.

The liability for AROs primarily relates to facilities that are subject to the CCR Rule, principally ash ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and ~~2 – and facilities that are subject to the CCR Rule, principally ash ponds.~~2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded ~~because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore,~~as the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.

~~As a result of the final CCR Rule discussed above, Alabama Power, Gulf Power, and Mississippi Power recorded new~~The cost estimates for AROs ~~for facilities that are subject~~related to the ~~CCR Rule. Georgia Power had previously recorded AROs as a result~~disposal of ~~state requirements in Georgia which closely align with the requirements of the~~ CCR ~~Rule. The cost estimates~~ are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for ~~closure in place or by other methods.~~closure. As further analysis is performed ~~including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site,~~ and ~~the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,~~closure details are developed, the traditional electric operating companies ~~expect to~~will continue to periodically update these ~~estimates.~~cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.

Given the significant judgment involved in estimating AROs, Southern Company considers the liabilities for AROs to be critical accounting estimates.

~~See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.~~

Pension and Other Postretirement Benefits

Southern Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Southern Company and Subsidiary Companies 2015 Annual Report~~

Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.

Key elements in determining Southern Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, Southern Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. ~~For~~Beginning in 2016, Southern Company ~~has~~ adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

component of net periodic pension and other postretirement benefit plan expense ~~will decrease~~decreased by approximately $96 million in 2016.

The following table illustrates the sensitivity to changes in Southern Company's long-term assumptions with respect to the assumed discount rate, the assumed salaries, and the assumed long-term rate of return on plan assets:



Change in Assumption	Increase/(Decrease) in Total Benefit Expense for ~~2016~~2018	Increase/(Decrease) in Projected Obligation for Pension Plan at December 31, ~~2015~~2017	Increase/(Decrease) in Projected Obligation for Other Postretirement Benefit Plans at December 31, ~~2015~~2017
	(in millions)
25 basis point change in discount rate	$~~30/~~40/$~~(29)~~(38)	$~~353/~~504/$~~(335)~~(476)	$~~56/~~68/$~~(53)~~(65)
25 basis point change in salaries	$~~12/~~24/$~~(11)~~(23)	$~~91/~~119/$~~(88)~~(115)	$–/$–
25 basis point change in long-term return on plan assets	$~~25/~~33/$~~(25)~~(33)	N/A	N/A

N/A – Not applicable

See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.

Goodwill and Other Intangible Assets

The acquisition method of accounting requires the assets acquired and liabilities assumed to be recorded at the date of acquisition at their respective estimated fair values. Southern Company recognizes goodwill as of the acquisition date, as a residual over the fair values of the identifiable net assets acquired. Goodwill is tested for impairment on an annual basis in the fourth quarter of the year as well as on an interim basis as events and changes in circumstances occur. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure in 2016, goodwill totaled approximately $6.3 billion at December 31, 2017.

Definite-lived intangible assets acquired are amortized over the estimated useful lives of the respective assets to reflect the pattern in which the economic benefits of the intangible assets are consumed. Whenever events or changes in circumstances indicate that the carrying amount of the intangible assets may not be recoverable, the intangible assets will be reviewed for impairment. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure and PPA fair value adjustments resulting from Southern Power's acquisitions, other intangible assets, net of amortization totaled approximately $873 million at December 31, 2017.

The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can significantly impact Southern Company's results of operations. Fair values and useful lives are determined based on, among other factors, the expected future period of benefit of the asset, the various characteristics of the asset, and projected cash flows. As the determination of an asset's fair value and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, Southern Company considers these estimates to be critical accounting estimates.

See Note 1 to the financial statements under "Goodwill and Other Intangible Assets and Liabilities" for additional information regarding Southern Company's goodwill and other intangible assets and Note 12 to the financial statements for additional information related to Southern Company's recent acquisitions and proposed dispositions.

Derivatives and Hedging Activities

Derivative instruments are recorded on the balance sheets as either assets or liabilities measured at their fair value, unless the transactions qualify for the normal purchases or normal sales scope exception and are instead subject to traditional accrual accounting. For those transactions that do not qualify as a normal purchase or normal sale, changes in the derivatives' fair values are recognized concurrently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, derivative gains and losses offset related results of the hedged item in the income statement in the case of a fair value hedge, or gains and losses are deferred in OCI until the hedged transaction affects earnings in the case of a cash flow hedge. Certain subsidiaries of Southern Company enter into energy-related derivatives that are designated as regulatory hedges where gains and losses are initially recorded as regulatory liabilities and assets and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through billings to customers.

Southern Company uses derivative instruments to reduce the impact to the results of operations due to the risk of changes in the price of natural gas, to manage fuel hedging programs per guidelines of state regulatory agencies, and to mitigate residual changes in the price of electricity, weather, interest rates, and foreign currency exchange rates. The fair value of commodity derivative

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

instruments used to manage exposure to changing prices reflects the estimated amounts that Southern Company would receive or pay to terminate or close the contracts at the reporting date. To determine the fair value of the derivative instruments, Southern Company utilizes market data or assumptions that market participants would use in pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique.

Southern Company classifies derivative assets and liabilities based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The determination of the fair value of the derivative instruments incorporates various required factors. These factors include:

the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);

events specific to a given counterparty; and

the impact of Southern Company's nonperformance risk on its liabilities.

Given the assumptions used in pricing the derivative asset or liability, Southern Company considers the valuation of derivative assets and liabilities a critical accounting estimate. See FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein for more information.

Contingent Obligations

Southern Company is subject to a number of federal and state laws and regulations as well as other factors and conditions that subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. Southern Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect Southern Company's results of operations, cash flows, or financial condition.

Recently Issued Accounting Standards

Revenue

~~The Financial Accounting Standards Board's (FASB)~~In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers ~~revises~~(ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

Most of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements.

Southern Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. Southern Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.

The new standard is effective for ~~fiscal years~~reporting periods beginning after December 15, 2017. Southern Company ~~continues~~applied the modified retrospective method of adoption effective January 1, 2018. Southern Company also utilized practical expedients which allowed it to ~~evaluate~~apply the ~~requirements~~standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC ~~606. The ultimate impact~~606 did not result in a cumulative-effect adjustment.

Table of ~~the new standard has not yet been determined.~~Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Leases

~~On April 7, 2015,~~In February 2016, the FASB issued ~~Accounting Standards Update (ASU)~~ASU No. ~~2015-03,~~2016-02, ~~Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs~~Leases (Topic 842) (ASU ~~2015-03)~~2016-02). ASU ~~2015-03~~2016-02 requires ~~that debt issuance costs related~~lessees to ~~a recognized debt liability be presented in~~recognize on the balance sheet as a ~~direct deduction from the carrying amount of that debt~~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. ASU 2016-02 is effective for fiscal years beginning after December 15, ~~2015. As permitted,~~2018 and Southern Company ~~elected to early~~will adopt the ~~guidance~~new standard effective January 1, 2019.

Southern Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, Southern Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers and PPAs where certain of Southern Company's subsidiaries are the lessee and to land and outdoor lighting where certain of Southern Company's subsidiaries are the lessor. The traditional electric operating companies are currently analyzing pole attachment agreements, and a lease determination has not been made at this time. While Southern Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet.

Other

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as ofrestricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December ~~31, 2015~~15, 2017, and will be applied ~~its provisions~~ retrospectively to each ~~prior~~ period presented. Southern Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.

On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for periods beginning on or after December 15, 2019, with early adoption permitted. Southern Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements.

On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for ~~comparative purposes. The new guidance resulted in an adjustment to~~capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of ~~debt issuance~~the service cost component and the other components of net periodic pension and postretirement benefit costs asin the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an ~~offset~~increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. Southern Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.

On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related ~~debt balances primarily in long-term debt totaling $202 million as of~~presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December ~~31, 2014. These debt issuance costs were previously presented within unamortized debt issuance expense. Other than the reclassification, the~~15, 2018, with early adoption ofpermitted. Southern Company adopted ASU ~~2015-03 did not have an~~2017-12 effective January 1, 2018 with no material impact on ~~the results of operations, cash flows, or~~its financial ~~condition of Southern Company. See Notes 6 and 10 to the financial statements for disclosures impacted by ASU 2015-03.~~statements.

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Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

~~On May 1, 2015, the FASB issued ASU No. 2015-07,~~ ~~Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)~~ (ASU 2015-07), effective for fiscal years beginning after December 15, 2015. As permitted, Southern Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of Southern Company. See Notes 2 and 10 to the financial statements for disclosures impacted by ASU 2015-07.

~~On November 20, 2015, the FASB issued ASU No. 2015-17,~~ ~~Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes~~ (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, Southern Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from deferred income taxes, current of $506 million, with $488 million to non-current accumulated deferred income taxes and $18 million to other deferred charges, as well as $2 million from accrued income taxes to non-current accumulated deferred income taxes in Southern Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of Southern Company. See Note 5 to the financial statements for disclosures impacted by ASU 2015-17.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Earnings in ~~2015 and 2014~~all periods presented were negatively affected by ~~revisions to the cost estimate for~~charges associated with the Kemper IGCC; however, Southern Company's financial condition remained stable at December 31, ~~2015 and December 31, 2014. Through December 31, 2015,~~2017.

The Southern Company has incurred non-recoverable cash expenditures of $1.95 billion and is expected to incur approximately $0.46 billion in additional non-recoverable cash expenditures through completion of the Kemper IGCC.

~~Southern Company's~~system's cash requirements primarily consist of funding ongoing operations, ~~funding the cash consideration for the Merger,~~ common stock dividends, capital expenditures, and debt maturities. The Southern Company system's capital expenditures and other investing activities include investments to meet projected long-term demand requirements, including to build new electric generation facilities, to maintain existing electric generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing electric generating units, to expand and improve electric transmission and distribution facilities, to update and expand natural gas distribution systems, and for restoration following major storms. Operating cash flows provide a substantial portion of the Southern Company system's cash needs. For the three-year period from ~~2016~~2018 through ~~2018,~~2020, Southern Company's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. The Southern Company system's projected capital expenditures in that period include investments to build new generation facilities, to maintain existing generation facilities, to add environmental modifications to existing generating units, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. Southern Company plans to finance future cash needs in excess of its operating cash flows primarily by accessing borrowings from financial institutions and through debt and equity issuances in the capital markets. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit arrangements to meet future capital and liquidity needs. See ~~FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" and "Sources~~"Sources of Capital," ~~"Financing~~"Financing Activities," and ~~"Capital~~"Capital Requirements and Contractual ~~Obligations"~~Obligations" herein for additional information.

Southern Company's investments in the qualified pension ~~plan~~plans and the nuclear decommissioning trust funds ~~decreased~~increased in value as of December 31, ~~2015~~2017 as compared to December 31, ~~2014.~~2016. No contributions to the qualified pension plan were made for the year ended December 31, ~~2015,~~2017 and no mandatory contributions to the qualified pension ~~plan~~plans are anticipated during ~~2016.~~2018. See ~~"Contractual Obligations"~~"Contractual Obligations" herein and Notes 1 and 2 to the financial statements under ~~"Nuclear Decommissioning"~~"Nuclear Decommissioning" and ~~"Pension~~"Pension Plans," respectively, for additional information.

Net cash provided from operating activities in ~~2015~~2017 totaled ~~$6.3~~$6.4 billion, an increase of ~~$459 million~~$1.5 billion from ~~2014.~~2016. The increase in net cash provided from operating activities was primarily due to ~~an increase~~increases of $1.2 billion related to operating activities of Southern Company Gas, which was acquired on July 1, 2016, and $1.0 billion related to voluntary contributions to the qualified pension plan in ~~fuel cost recovery,~~2016, partially offset by the timing of vendor payments. Net cash provided from operating activities in ~~2014~~2016 totaled ~~$5.8~~$4.9 billion, a decrease of ~~$282 million~~$1.4 billion from ~~2013.~~2015. Significant changes in operating cash flow for ~~2014~~2016 as compared to ~~2013~~2015 included ~~$500 million~~approximately $1.0 billion of voluntary contributions to the qualified pension plan in 2016 and ana $1.2 billion increase in ~~receivables due to under recovered fuel costs, partially offset by an increase in accrued compensation.~~

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Southern Company~~unutilized ITCs and ~~Subsidiary Companies 2015 Annual Report~~PTCs.

Net cash used for investing activities in 2017, 2016, and 2015 ~~2014, and 2013~~ totaled ~~$7.3~~$7.2 billion, ~~$6.4~~$20.0 billion, and ~~$5.7~~$7.3 billion, respectively. The cash used for investing activities in ~~each of these years~~2017 was primarily due to ~~gross property additions for~~the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions. The cash used for investing activities in 2016 was primarily due to the closing of the Merger, the acquisition of PowerSecure, Southern Company Gas' investment in SNG, the traditional electric operating companies' construction of electric generation, transmission, and distribution facilities and installation of equipment at electric generating facilities to comply with environmental standards, and Southern Power's acquisitions and construction of renewable facilities and a natural gas facility. The cash used for investing activities in 2015 was primarily due to the traditional electric operating companies' gross property additions for installation of equipment at electric generating facilities to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, Southern Power's acquisitions of solar facilities, and purchases of nuclear fuel.

Net cash provided from financing activities totaled $1.0 billion in 2017 primarily due to net issuances of long-term and short-term debt, partially offset by common stock dividend payments. Net cash provided from financing activities totaled $15.7 billion in 2016 primarily due to issuances of long-term debt and common stock associated with completing the Merger and funding the subsidiaries' continuous construction programs, Southern Power's acquisitions, and Southern Company Gas' investment in SNG, partially offset by redemptions of long-term debt and common stock dividend payments. Net cash provided from financing activities totaled $1.7 billion in 2015 primarily due to issuances of long-term debt and common stock and an increase in short-term debt, partially offset by common stock dividend payments and redemptions of long-term debt and preferred and preference stock. Net cash provided from financing activities totaled $644 million in 2014 due to issuances of long-term debt and common stock, partially offset by common stock dividend payments, redemptions of long-term debt, and a reduction in short-term debt. Net cash used for financing activities totaled $324 million in 2013 due to redemptions of long-term debt and payments of common stock dividends, partially offset by issuances of long-term debt and common stock and an increase in notes payable. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes in ~~2015~~2017 included ~~increases~~decreases of ~~$4.9~~$7.3 billion and $0.8 billion in ~~plant in service, net~~accumulated deferred income taxes and deferred charges related to income taxes, respectively, and an increase of ~~depreciation and $1.3~~$7.0 billion in ~~construction work~~deferred credits related to

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

income taxes primarily resulting from the impacts of the Tax Reform Legislation; an increase of $1.4 billion in ~~progress for~~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; increases of $0.7~~facilities, Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions, largely offset by the $2.8 billion ~~in other regulatory assets, deferred and $1.6 billion in AROs primarily resulting from impacts~~write-down of the ~~CCR Rule;~~gasification portions of the Kemper County energy facility and payments of $1.7 billion received by Georgia Power under the Guarantee Settlement Agreement; an increase of ~~$3.4~~$3.1 billion in ~~short-term and~~ long-term debt (including amounts due within one year) primarily to fund the ~~subsidiaries'~~Southern Company system's continuous construction programs and for ~~other~~ general corporate purposes; and ~~an increase~~a decrease of ~~$1.2~~$1.1 billion in ~~accumulated deferred income taxes~~total stockholder's equity primarily ~~as a result~~related to the Kemper County energy facility charges, partially offset by the issuance of ~~bonus depreciation.~~additional shares of common stock. See ~~Note 1~~FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" and "Financing Activities" herein and Note 53 to the financial statements under "Nuclear Construction" and "Kemper County Energy Facility" for additional ~~information regarding AROs and deferred income taxes, respectively.~~information.

At the end of ~~2015,~~2017, the market price of Southern Company's common stock was ~~$46.79~~$48.09 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was ~~$22.59~~$23.99 per share, representing a market-to-book value ratio of ~~207%~~201%, compared to ~~$49.11, $21.98,~~$49.19, $25.00, and ~~223%~~197%, respectively, at the end of ~~2014.~~2016.

Southern Company's consolidated ratio of common equity to total capitalization plus short-term debt was 31.5% and 33.3% at December 31, 2017 and 2016, respectively. See Note 6 to the financial statements for additional information.

Sources of Capital

Southern Company intends to meet its future capital needs through operating cash flows, ~~short-term~~borrowings from financial institutions, and debt ~~term loans,~~ and ~~external security issuances.~~equity issuances in the capital markets. Equity capital can be provided from any combination of the Company's stock plans, private placements, or public offerings. The amount and timing of additional equity ~~capital~~ and debt issuances in ~~2016,~~2018, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital ~~requirements.~~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 ~~Power~~Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, ~~term loans, short-term~~ 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 any potential sale of a 33% equity interest in a newly-formed holding company that owns substantially all of its solar assets, if completed. Southern Company Gas also plans to utilize the proceeds from the pending asset sales of two of its natural gas distribution utilities. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See FUTURE EARNINGS POTENTIAL – "General" herein for additional information.

In addition, in 2014, Georgia Power ~~may make borrowings through a loan guarantee agreement (Loan~~entered into the Loan Guarantee ~~Agreement), between Georgia Power and~~Agreement with the DOE, under which the proceeds of ~~which~~borrowings may be used to reimburse Georgia Power for ~~a portion~~Eligible Project Costs incurred in connection with its construction of ~~certain costs of construction relating to~~ Plant Vogtle Units 3 and ~~4 that are eligible for financing under the Loan Guarantee Agreement (Eligible Project Costs).~~4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of December 31, 2017, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.

On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements under ~~"DOE~~"DOE Loan Guarantee ~~Borrowings"~~Borrowings" for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note 3 to the financial statements under ~~"Retail Regulatory Matters – Georgia Power –~~ "Nuclear ~~Construction"~~Construction" for additional information regarding Plant Vogtle Units 3 and 4.

~~Eligible Project Costs incurred through December 31, 2015 would allow for borrowings of up to $2.3 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.2 billion.~~

Mississippi Power received $245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for the commercial operation of the Kemper IGCC. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

Mississippi Power expects the Kemper IGCC to qualify for additional DOE grants included in the recently passed Consolidated Appropriations Act of 2015, which are expected to be used to reduce future rate impacts for customers. The ultimate outcome of this matter cannot be determined at this time.

The issuance of securities by the traditional electric operating companies and Nicor Gas is generally subject to the approval of the applicable state ~~PSC.~~PSC or other applicable state regulatory agency. The issuance of all securities by Mississippi Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company and certain of its

~~II-39~~

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Southern Company and Subsidiary Companies 2015 Annual Report~~

subsidiaries file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

well as the securities registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

Southern Company, each traditional electric operating company, and Southern Power generally obtain financing separately without credit support from any affiliate. ~~See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.~~ The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company in the Southern Company system.

In addition, Southern Company Gas Capital obtains external financing for Southern Company Gas and its subsidiaries, other than Nicor Gas, which obtains financing separately without credit support from any affiliates. Nicor Gas' commercial paper program supports its working capital needs as Nicor Gas is not permitted to make money pool loans to affiliates. All of the other Southern Company Gas subsidiaries benefit from Southern Company Gas Capital's commercial paper program.

See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.

As of December 31, ~~2015,~~2017, Southern Company's current liabilities exceeded current assets by ~~$2.6~~$3.5 billion, ~~primarily~~ due to $3.9 billion of long-term debt that is due within one year (comprised of ~~$2.7~~approximately $1.0 billion ~~including~~at the parent company, $0.9 billion at Georgia Power, $1.0 billion at Mississippi Power, $0.8 billion at Southern Power, and $0.2 billion at Southern Company Gas) and $2.4 billion of notes payable (comprised of approximately ~~$0.5~~$0.6 billion at the parent company, $0.2 billion at ~~Alabama Power, $0.7 billion at~~ Georgia Power, $0.1 billion at ~~Gulf Power, $0.7 billion at Mississippi~~Southern Power, and ~~$0.4~~$1.5 billion at Southern ~~Power. In addition, Mississippi Power has $0.5 billion in short-term bank loans scheduled to mature on April 1, 2016.~~Company Gas). 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 ~~Power~~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 ~~Power,~~Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.

The financial condition of Mississippi Power and its ability to obtain financing needed for normal business operations and completion of construction and start-up of the Kemper IGCC were adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA, the required refund of approximately $371 million of Mirror CWIP rate collections, including associated carrying costs, the termination of the Mirror CWIP rate, and the required recapture of Phase II tax credits. On December 3, 2015, the Mississippi PSC approved the In-Service Asset Rate Order which, among other things, provides for retail rate recovery of an annual revenue requirement of approximately $126 million which became effective on December 17, 2015. Mississippi Power plans to refinance its 2016 debt maturities with bank term loans and to obtain the funds required for construction and other purposes from operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

At December 31, ~~2015,~~2017, Southern Company and its subsidiaries had approximately ~~$1.4~~$2.1 billion of cash and cash equivalents. Committed credit arrangements with banks at December 31, ~~2015~~2017 were as follows:


	Expires												Executable Term Loans				Due Within One Year				Expires												Executable Term Loans				Expires Within One Year
Company	2016		2017		2018		2020		Total		Unused		One Year		Two Years		Term Out		No Term Out		2018		2019		2020		2022		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)								(in millions)				(in millions)				(in millions)				(in millions)
Southern Company ^(a)	$	—	$	—	$	1,000	$	1,250	$	2,250	$	2,250	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—	$	—	$	—	$	—
Alabama Power	40		—		500		800		1,340		1,340		—		—		—		40		35		—		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		1,750		1,750		1,732		—		—		—		—		—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	80		30		165		—		275		275		50		—		50		30		30		25		225		—		280		280		45		—		20		10
Mississippi Power	220		—		—		—		220		195		30		15		45		175		100		—		—		—		100		100		—		—		—		100
Southern Power ^(b)	—		—		—		600		600		566		—		—		—		—
Southern Power Company^(b)																					—		—		—		750		750		728		—		—		—		—
Southern Company Gas^(c)																					—		—		—		1,900		1,900		1,890		—		—		—		—
Other	70		—		—		—		70		70		—		—		—		70		30		—		—		—		30		30		20		—		20		10
Total	$	410	$	30	$	1,665	$	4,400	$	6,505	$	6,428	$	80	$	15	$	95	$	315
Southern Company Consolidated																					$	195	$	25	$	725	$	7,200	$	8,145	$	8,094	$	65	$	—	$	40	$	155


(a)	~~Excludes~~Represents the ~~$8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein.~~Southern Company parent entity.

(b)

~~Excludes~~Does not include Southern Power's $120 million continuing letter of credit ~~agreements (Project Credit Facilities) assumed with the acquisition~~facility for standby letters of ~~certain solar facilities, which are non-recourse to Southern Power Company, the proceeds~~credit expiring in 2019, of which ~~are being used to finance project costs related to such solar facilities currently under construction. See Note 12 to~~$19 million remains unused at December 31, 2017.

(c)

Southern Company Gas, as the ~~financial statements under "Southern Power"~~parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for ~~additional information.~~which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

See Note 6 to the financial statements under ~~"Bank~~"Bank Credit ~~Arrangements"~~Arrangements" for additional information.

~~As reflected in the table above, in August 2015,~~In May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended ~~and restated~~certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018.

~~II-40~~

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

~~dates from 2018 to 2020.~~Also in May 2017, Southern Company Gas Capital and ~~Southern Power Company increased~~Nicor Gas terminated their ~~borrowing ability under these~~existing credit arrangements ~~to $1.25 billion from $1.0~~for $1.3 billion and $700 million, respectively, which were to ~~$600 million from $500 million, respectively. Georgia Power increased its borrowing ability by $150 million under its facility maturing~~mature in ~~2020~~2017 and terminated its aggregate $150 million facilities maturing in 2016. In September 2015, Southern Company entered into an additional multi-year credit arrangement for $1 billion with a maturity date of 2018. Also in September 2015, Alabama Power2018, and entered into a new multi-year credit arrangement with $1.4 billion and $500 million ~~three-year~~currently allocated to Southern Company Gas Capital and Nicor Gas, respectively, maturing in 2022. Pursuant to the new multi-year credit arrangement, ~~which replaced a majority of~~the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. In September 2017, Alabama ~~Power's bilateral credit arrangements. In November 2015, Gulf~~ Power also amended ~~and restated certain of~~ its $500 million multi-year credit ~~arrangements~~arrangement, which, among other things, extended the maturity date from 2018 to 2020. In November 2017, Gulf Power amended $195 million of its multi-year credit arrangements to extend the maturity dates from ~~2016~~2017 and 2018 to 2020 and Mississippi Power amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018.

Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, contain covenants that limit debt levels and contain ~~cross acceleration~~cross-acceleration or ~~cross default~~cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such ~~cross default~~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~~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 December 31, 2017, Southern Company, the traditional electric operating companies, ~~and~~ Southern Power Company, ~~are currently~~Southern Company Gas, and Nicor Gas 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.

A portion of the unused credit with banks is allocated to provide liquidity support to the ~~traditional operating companies' pollution control~~ revenue bonds of the traditional electric operating companies and the commercial paper ~~programs.~~programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate ~~pollution control~~ revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of December 31, ~~2015~~2017 was approximately ~~$1.8 billion.~~$1.5 billion as compared to $1.9 billion at December 31, 2016. In addition, at December 31, ~~2015,~~2017, the traditional electric operating companies had approximately ~~$181~~$714 million of ~~fixed rate pollution control~~ revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to December 31, 2017, $50 million of these revenue bonds of Mississippi Power which were in a long-term interest rate mode were remarketed in an index rate mode.

At December 31, 2017, Pivotal Utility Holdings, Inc., a subsidiary of Southern Company ~~intends to initially fund~~Gas, had $200 million of gas facility revenue bonds outstanding. The Elizabethtown Gas asset sale agreement requires that bonds representing $180 million of the ~~cash consideration~~total that are currently eligible for ~~the Merger using a mix of debt and equity. Southern Company finances its capital needs~~redemption at par be redeemed on ~~a portfolio basis and expects to issue approximately $8.0 billion in debt~~or prior to closing the Merger and approximately $1.2 billion in equity during 2016. This capital is expected to provide funding for the Merger, Southern Power growth opportunities, and other Southern Company system capital projects. Southern Company expects to issue the debt to fund the Merger Consideration in several tranches including long-dated maturities. The amount of debt issued at each maturity will depend on prevailing market conditions at the time of the offering and other factors. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available.

The Bridge Agreement provides for total loan commitments in an aggregate amount of $8.1 billion to fund the payment of the cash consideration payable under the Merger Agreement and other cash payments required in connection with the consummation of the ~~Merger, the Bridge Agreement~~sale. See FUTURE EARNINGS POTENTIAL – "General" herein and ~~the borrowings thereunder, the other financing transactions related~~Note 6 to the ~~Merger, and the payment of fees and expenses incurred in connection with the foregoing. If funded, the loan~~financial statements under ~~the Bridge Agreement will mature and be payable in full on the date that is 364 days after the funding of the commitments under the Bridge Agreement (Closing Date).~~

~~In connection with the Bridge Agreement, Southern Company will pay a ticking fee~~"Gas Facility Revenue Bonds" for the benefit of the lenders thereto, accruing from November 21, 2015, in an amount equal to 0.125% per annum of the aggregate commitments under the Bridge Agreement, which fee will accrue through the earlier of (i) the date of termination of the commitments and (ii) the Closing Date. Additionally, under the terms of the Bridge Agreement, Southern Company is required to pay certain customary fees to the lenders as set forth in related letters. As of December 31, 2015, Southern Company had no outstanding loans under the Bridge Agreement.additional information.

Southern Company, the traditional electric operating companies ~~and~~(other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described ~~above, excluding the Bridge Agreement. Southern Company, the traditional operating companies, and Southern Power may also borrow through various other arrangements with banks.~~above. Short-term borrowings are included in notes payable in the balance sheets.

~~II-41~~

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

Details of short-term borrowings were as follows:


	Short-term Debt at the End of the Period				Short-term Debt During the Period ^(*)						Short-term Debt at the End of the Period				Short-term Debt During the Period ^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding		Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)		(in millions)				(in millions)				(in millions)
December 31, 2017:
Commercial paper											$	1,832	1.8	%	$	2,117	1.3	%	$	2,946
Short-term bank debt											607		2.3	%	555		2.1	%	1,020
Total											$	2,439	1.9	%	$	2,672	1.5	%
December 31, 2016:
Commercial paper											$	1,909	1.1	%	$	976	0.8	%	$	1,970
Short-term bank debt											123		1.7	%	176		1.7	%	500
Total											$	2,032	1.1	%	$	1,152	1.1	%
December 31, 2015:
Commercial paper	$	740	0.7	%	$	842	0.4	%	$	1,563	$	740	0.7	%	$	842	0.4	%	$	1,563
Short-term bank debt	500		1.4	%	444		1.1	%	795		500		1.4	%	444		1.1	%	795
Total	$	1,240	0.9	%	$	1,286	0.5	%			$	1,240	0.9	%	$	1,286	0.5	%
December 31, 2014:
Commercial paper	$	803	0.3	%	$	754	0.2	%	$	1,582
Short-term bank debt	—		—	%	98		0.8	%	400
Total	$	803	0.3	%	$	852	0.3	%
December 31, 2013:
Commercial paper	$	1,082	0.2	%	$	993	0.3	%	$	1,616
Short-term bank debt	400		0.9	%	107		0.9	%	400
Total	$	1,482	0.4	%	$	1,100	0.3	%


(*)	Average and maximum amounts are based upon daily balances during the ~~twelve-month~~12-month periods ended December 31, ~~2015, 2014,~~2017, 2016, and ~~2013.~~2015.

In addition to the short-term borrowings of Southern Power Company included in the table above, at December 31, 2016 and 2015, Southern Power Company subsidiaries had credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. The Project Credit Facilities were fully repaid in January 2017. For the year ended December 31, 2016, the Project Credit Facilities had ~~total amounts~~a maximum amount outstanding as of ~~December 31, 2015~~$828 million and an average amount outstanding of ~~$137~~$566 million at a weighted average interest rate of ~~2.0%.~~2.1% and had total amounts outstanding of $209 million at a weighted average interest rate of 2.1% at December 31, 2016. For the year ended December 31, 2015, the Project Credit Facilities had a maximum amount outstanding of $137 million and an average amount outstanding of $13 million at a weighted average interest rate of 2.0% and had total amounts outstanding of $137 million at a weighted average interest rate of 2.0% at December 31, 2015.

Furthermore, in connection with the acquisition of a solar facility in July 2016, a subsidiary of Southern Power Company assumed a $217 million construction loan, which was fully repaid in September 2016. During this period, the credit agreement had a maximum amount outstanding of $217 million and an average amount outstanding of $137 million at a weighted average interest rate of 2.2%.

The Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank ~~notes,~~term loans, and operating cash flows.

Financing Activities

During ~~2015,~~2017, Southern Company issued approximately ~~6.6~~14.6 million shares of common stock primarily through ~~the~~ employee equity compensation ~~plan~~plans and received proceeds of approximately ~~$256~~$659 million. ~~During~~

In addition, during the ~~first nine months~~second and third quarters of ~~2015, all sales under the Southern Investment Plan and the Employee Savings Plan were funded with shares acquired on the open market by independent plan administrators. In October 2015,~~2017, Southern Company ~~began issuing~~issued a total of approximately 2.7 million shares of common stock through ~~the~~at-the-market issuances pursuant to sales agency agreements related to Southern ~~Investment Plan~~Company's continuous equity offering program and the Employee Savings Plan. The Company may satisfy its obligations with respect to the plans in several ways, including through using newly issued shares or treasury shares or acquiring shares on the open market through the independent plan administrators.

On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director stock plans, including through stock option exercises, until December 31, 2017. Under this program, approximately 2.6 million shares were repurchased in 2015 at a total costreceived cash proceeds of approximately ~~$115 million. No further repurchases under the program are anticipated.~~$134 million, net of $1.1 million in fees and commissions.

~~II-42~~

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the year ended December 31, ~~2015:~~2017:


Company	Senior Note Issuances		Senior Note Maturities and Redemptions		Revenue Bond Issuances and Reofferings of Purchased Bonds^(a)		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions and Maturities^(b)		Senior Note Issuances		Senior Note Maturities and Redemptions		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)													(in millions)
Southern Company(b)	$	600	$	400	$	—	$	—	$	1,400		$	—	$	300	$	400	$	—	$	—	$	950		$	400
Alabama Power	975		650		80		134		—			—		1,100		525		—		36		—			—
Georgia Power	500		1,175		409		267		1,000			6		1,350		450		65		65		370			17
Gulf Power	—		60		13		13		—			—		300		85		—		—		6			—
Mississippi Power	—		—		—		—		275			353		—		35		—		—		40			962
Southern Power	1,650		525		—		—		402			4		525		500		—		—		43			18
Southern Company Gas^(c)														450		—		—		—		400			22
Other	—		—		—		—		—			17		—		—		—		—		—			15
Elimination^(c)	—		—		—		—		(275		)	—
Total	$	3,725	$	2,810	$	502	$	414	$	2,802		$	380
Elimination^(d)														—		—		—		—		(40		)	(602		)
Southern Company Consolidated														$	4,025	$	1,995	$	65	$	101	$	1,769		$	832

(a)

Includes a reoffering by Alabama Power of $80.0 million aggregate principal amount of revenue bonds purchased and held since April 2015; reofferings by Georgia Power of $135.2 million, $104.6 million, and $65.0 million aggregate principal amount of revenue bonds purchased and held since 2010, 2013, and April 2015, respectively; and a reoffering by Gulf Power of $13.0 million aggregate principal amount of revenue bonds purchased and held in July 2015. Also includes repurchases and reofferings by Georgia Power of $94.6 million and $10.0 million aggregate principal amount of revenue bonds in August 2015 in connection with optional tenders.


~~(b)~~	Includes reductions in capital lease obligations resulting from cash payments under capital leases.


(b)	Represents the Southern Company parent entity.


(c)	~~Intercompany loan~~The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas.


(d)	Includes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements.

In June 2015, Southern Company issued $600 million aggregate principal amount of Series 2015A 2.750% Senior Notes due June 15, 2020. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes.

In September 2015, Southern Company entered into a $400 million aggregate principal amount 18-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.

~~Also in September 2015, Southern Company repaid at maturity $400 million aggregate principal amount of its Series 2010A 2.375% Senior Notes due September 15, 2015.~~

In October 2015, Southern Company issued $1.0 billion aggregate principal amount of Series 2015A 6.25% Junior Subordinated Notes due October 15, 2075. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes.

In November and December 2015, Southern Company entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to anticipated debt issuances. The notional amount of the swaps totaled $2 billion. Subsequent to December 31, 2015, Southern Company entered into an additional $700 million notional amount of forward-starting interest rate swaps.

Except as otherwise described herein, Southern ~~Company's~~Company and its subsidiaries used the proceeds of ~~the~~ debt issuances ~~shown in the table above~~ for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital and, for the subsidiaries, their continuous construction ~~programs~~programs.

In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.

In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057 and ~~for~~$300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR.

Also in June 2017, Southern Company entered into two $100 million aggregate principal amount short-term floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR.

In August 2017, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank.

Also in August 2017, Southern Company repaid at maturity $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes.

In November 2017, Southern Company issued $450 million aggregate principal amount of Series 2017B 5.25% Junior Subordinated Notes due December 1, 2077.

In September 2017, Alabama Power ~~its growth strategy.~~

issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A ~~portion~~Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The majority of the proceeds ~~of Alabama Power's senior note issuances~~ were used in ~~May 2015~~October 2017 to redeem ~~6.48~~all 2 million shares ($~~162~~50 million aggregate stated capital) of Alabama Power's ~~5.20% Class A Preferred~~6.50% Series Preference Stock, at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of Alabama Power's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and 6.06 million shares ($150 million aggregate stated capital) of Alabama Power's ~~5.625%~~6.45% Series Preference Stock, ~~at a redemption price~~and 1.52 million shares ($38 million aggregate stated capital) of ~~$25 per share plus accrued and unpaid dividends to the redemption date.~~Alabama Power's 5.83% Class A Preferred Stock.

In June 2017, Georgia ~~Power's "Other Long-Term Debt Issuances" reflected~~Power entered into two short-term floating rate bank loans in ~~the table above include borrowings in June and December 2015 under the FFB Credit Facility in an~~ aggregate principal ~~amount~~amounts of ~~$600~~$50 million and ~~$400~~$150 million, ~~respectively. The interest~~with maturity dates of December 1, 2017 and May 31, 2018, respectively, and one long-term floating rate bank

~~II-43~~

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

~~applicable to the $600~~loan of $100 million, ~~principal amount is 3.283% and the interest rate applicable to the $400 million principal amount is 3.072%, both for an interest period that extends to the final~~with a maturity date of ~~February 20, 2044.~~June 28, 2018, which was amended in August 2017 to extend the maturity date to October 26, 2018. These loans bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank.

In August 2017, Georgia Power repaid its $50 million floating rate bank loan due December 1, 2017 and $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. In December 2017, Georgia Power repaid the remaining $250 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement.

Subsequent to December 31, 2017, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.

As reflected in the table above under other long-term debt issuances, in September 2017, Georgia Power also issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used to ~~reimburse~~redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia ~~Power for Eligible Project Costs relating to the construction~~Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of ~~Plant Vogtle Units 3 and 4.~~Georgia Power's 6.50% Series 2007A Preference Stock.

In March ~~2015, Georgia~~2017, Gulf Power ~~entered into a $250~~extended the maturity of its $100 million ~~aggregate principal amount three-month~~short-term floating rate bank loan bearing interest based on one-month ~~LIBOR. The~~LIBOR from April 2017 to October 2017 and subsequently repaid the loan ~~was repaid at maturity.~~in May 2017.

In April 2015, Mississippi Power entered into two short-term floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. A portion of the proceeds of ~~these loans were~~Gulf Power's senior note issuances was used ~~for~~in June 2017 to redeem 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.

In June 2017, Mississippi Power prepaid $300 million of the ~~repayment of term loans in an aggregate~~outstanding principal amount of $275 million. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.

In addition to the amounts reflected in the table above, Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant tounder its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of approximately $301 million bearing interest based on one-month LIBOR,$1.2 billion unsecured term loan, which matures on ~~December 1, 2017. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" for additional information.~~March 30, 2018.

In ~~June 2015, Gulf~~September 2017, Southern Power ~~entered into a $40~~amended its $60 million aggregate principal amount ~~three-month~~ floating rate ~~bank~~term loan ~~bearing interest based on one-month LIBOR. The loan was repaid at maturity.~~

~~In October 2015, Gulf Power entered into forward-starting interest rate swaps~~ to, ~~hedge exposure to interest rate changes related to an anticipated debt issuance. The notional amount of~~among other things, increase the ~~swaps totaled $80 million.~~

~~Subsequent to December 31, 2015, Alabama Power issued $400 million~~ aggregate principal amount ~~of Series 2016A 4.30% Senior Notes due January 2, 2046. The proceeds were used~~ to ~~repay at~~$100 million and extend the maturity ~~$200 million aggregate principal amount of its Series FF 5.20% Senior Notes due January 15, 2016 and for general corporate purposes, including Alabama Power's continuous construction program.~~

~~Subsequent~~date from September 2017 to ~~December 31, 2015, Southern Power borrowed $182 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.0%.~~October 2018.

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.

Credit Rating Risk

At December 31, 2017, Southern Company and its subsidiaries dodid 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 December 31, ~~2015~~2017 were as follows:


Credit Ratings	Maximum Potential Collateral Requirements		Maximum Potential Collateral Requirements
	(in millions)		(in millions)
At BBB and/or Baa2	$	12	$	40
At BBB- and/or Baa3	$	508	$	665
Below BBB- and/or Baa3	$	2,432
At BB+ and/or Ba1^(*)			$	2,390



()	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. ~~Management believes that the portfolio is well-diversified with no significant concentrations of risk.~~

The composition of Southern Company Gas' pension plan assets as of December 31, 2017 and 2016, along with the targets, is presented below:

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	Target		2017		2016
Pension plan assets:
Equity	53	%	65	%	69	%
Fixed Income	15		19		20
Cash	2		6		1
Other	30		10		10
Balance at end of period	100	%	100	%	100	%

Table of Contents Index to Financial Statements

NOTES (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

Fair Value Measurements Using
Quoted Prices in Active Markets for Identical Assets
Significant
Other
Observable
Inputs

Significant
Unobservable
Inputs
Net Asset Value as a Practical Expedient
As of December 31, 2014: (Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Assets:
Domestic equity* $ 147
$ 56
$ —
$ —
$ 203
International equity* 36
67
—
—
103
Fixed income:
U.S. Treasury, government, and agency bonds —
29
—
—
29
Mortgage- and asset-backed securities —
6
—
—
6
Corporate bonds —
39
—
—
39
Pooled funds —
41
—
—
41
Cash equivalents and other 9
27
—
—
36
Trust-owned life insurance —
381
—
—
381
Real estate investments 11
—
—
37
48
Private equity —
—
—
19
19
Total $ 203
$ 646
$ —
$ 56
$ 905
The fair values of Southern Company's (excluding Southern Company Gas) other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases.



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient		Total		Target Allocation		Actual Allocation
As of December 31, 2017:	(Level 1)		(Level 2)		(Level 3)		(NAV)
	(in millions)
Assets:
Domestic equity^(*)	$	132	$	35	$	—	$	—	$	167	37	%	40	%
International equity^(*)	47		76		—		—		123		23		23
Fixed income:											30		29
U.S. Treasury, government, and agency bonds	—		32		—		—		32
Corporate bonds	—		37		—		—		37
Pooled funds	—		55		—		—		55
Cash equivalents and other	10		—		—		—		10
Trust-owned life insurance	—		426		—		—		426
Real estate investments	16		—		—		36		52		5		5
Special situations	—		—		—		5		5		1		1
Private equity	—		—		—		20		20		4		2
Total	$	205	$	661	$	—	$	61	$	927	100	%	100	%



()	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. ~~Management believes that the portfolio is well-diversified with no significant concentrations~~

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient				Target Allocation		Actual Allocation
As of December 31, 2016:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Domestic equity^(*)	$	118	$	28	$	—	$	—	$	146	39	%	40	%
International equity^(*)	37		61		—		—		98		23		21
Fixed income:											29		31
U.S. Treasury, government, and agency bonds	—		24		—		—		24
Corporate bonds	—		30		—		—		30
Pooled funds	—		49		—		—		49
Cash equivalents and other	41		—		—		—		41
Trust-owned life insurance	—		382		—		—		382
Real estate investments	11		—		—		35		46		5		5
Special situations	—		—		—		5		5		1		1
Private equity	—		—		—		17		17		3		2
Total	$	207	$	574	$	—	$	57	$	838	100	%	100	%


(*)	Level 1 securities consist of ~~risk.~~actively traded stocks while Level 2 securities consist of pooled funds.

The fair values of Southern Company Gas' other postretirement benefit plan assets for the period ended December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Special situations (absolute return and hedge funds) investment assets are presented in the tables below based on the nature of the investment.



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient		Total
As of December 31, 2017:	(Level 1)		(Level 2)		(Level 3)		(NAV)
	(in millions)
Assets:
Domestic equity^(*)	$	3	$	69	$	—	$	—	$	72
International equity^(*)	—		22		—		—		22
Fixed income:
Pooled funds	—		24		—		—		24
Cash equivalents and other	2		—		—		1		3
Total	$	5	$	115	$	—	$	1	$	121


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

Table of Contents Index to Financial Statements

NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient		Total
As of December 31, 2016:	(Level 1)		(Level 2)		(Level 3)		(NAV)
	(in millions)
Assets:
Domestic equity^(*)	$	3	$	58	$	—	$	—	$	61
International equity^(*)	—		18		—		—		18
Fixed income:
Pooled funds	—		23		—		—		23
Cash equivalents and other	1		—		—		2		3
Total	$	4	$	99	$	—	$	2	$	105


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

The composition of Southern Company Gas' other postretirement benefit plan assets as of December 31, 2017 and 2016, along with the targets, is presented below:



	Target		2017		2016
Other postretirement benefit plan assets:
Equity	72	%	76	%	74	%
Fixed Income	24		20		23
Cash	1		2		1
Other	3		2		2
Total	100	%	100	%	100	%

Employee Savings Plan

Southern Company and its subsidiaries also ~~sponsors a~~sponsor 401(k) defined contribution ~~plan~~plans covering substantially all ~~employees. The Company provides an 85%~~employees and provide matching ~~contribution on~~contributions up to 6%specified percentages of an employee's ~~base salary.~~eligible pay. Total matching contributions made to the ~~plan~~plans for ~~2015~~2017, ~~2014~~2016, and ~~2013~~2015 were ~~$92~~$118 million, $87105 million, and $8492 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

On January 20, 2017, a purported 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, Atlanta Division, 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 that Southern Company, certain of its officers, and certain former Mississippi Power officers 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. On June 12, 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. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.

Southern Company and its subsidiaries are subject to certain claims 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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, ~~quality~~water, land, and ~~water standards,~~protection of other natural resources, 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 against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements.

~~AGL Resources Merger Litigation~~

AGL Resources and each member of the AGL Resources board of directors were named as defendants in four purported shareholder class action lawsuits filed in the United States District Court for the Northern District of Georgia in September and October 2015. These actions were filed on behalf of named plaintiffs and other AGL Resources shareholders challenging the Merger and seeking, among other things, preliminary and permanent injunctive relief enjoining the Merger, and, in certain circumstances, damages. Southern Company and Merger Sub were also named as defendants in two of these lawsuits. On October 23, 2015, the court consolidated the four lawsuits into a single action. On January 4, 2016, the parties filed a proposed stipulated

~~II-83~~

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~~NOTES (continued)~~

~~Southern Company and Subsidiary Companies 2015 Annual Report~~

~~order of dismissal, asking the court to dismiss the consolidated amended complaint without prejudice, which the court approved on January 5, 2016. See Note 12 under "Southern Company~~ – ~~Proposed Merger with AGL Resources" for additional information regarding the Merger.~~

Environmental Matters

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations ~~that cover~~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 conduct studies to determine the extent of any required cleanup and have ~~each~~recognized the estimated costs to clean up known impacted sites in the financial statements. A liability for environmental remediation costs is recognized only when a loss is determined to be probable and reasonably estimable. The traditional electric operating companies and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These ~~rates~~regulatory mechanisms are adjusted annually or as necessary within limits approved by the state ~~PSCs.~~PSCs or other applicable state regulatory agencies.

Georgia Power's environmental remediation liability as of December 31, ~~2015~~2017 and 2016 was ~~$29 million.~~$22 million and $17 million, respectively. Georgia Power has been designated or identified as a potentially responsible party ~~(PRP)~~ at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The PRPs at the Brunswick site have completed a removal action as ordered by the EPA. Additional response actions at this site are anticipated. In September 2015, Georgia Power entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between Georgia Power and ~~that PRP) for paying and performing certain investigation,~~ assessment ~~remediation, and other incidental activities at the Brunswick site. Assessment~~ and potential cleanup of ~~other~~such sites ~~are anticipated.~~is expected.

The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's financial statements.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately ~~$46~~$52 million and $44 million as of December 31, ~~2015~~.2017 and 2016, respectively. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf ~~Power~~Power's substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.

Table of Contents Index to Financial Statements

NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Southern Company Gas' environmental remediation liability as of December 31, 2017 and 2016 was $388 million and $426 million, 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 ~~final~~ultimate outcome of these matters cannot be determined at this ~~time. However, based~~time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management does not believe that additional liabilities, if any, at these sites would be material to theSouthern Company's financial ~~statements~~.statements.

Nuclear Fuel Disposal Costs

Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.

In ~~December~~ 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in their spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. ~~On March 19,~~In 2015, Georgia Power recovered approximately $18 million, based on its ownership interests, ~~and Alabama Power recovered approximately $26 million. In March 2015, Georgia Power~~which was credited ~~the award~~ to accounts where the original costs were charged, and ~~reduced~~used to reduce rate base, fuel, and cost of service for the benefit of customers. ~~In November~~Also in 2015, Alabama Power recovered approximately $26 million, which was applied to reduce the ~~retail-related proceeds to offset~~cost of service for the nuclear fuel expense under Rate ECR. See "Retail Regulatory Matters – Alabama Power – Nuclear Waste Fund Accounting Order" herein for additional information. In December 2015, Alabama Power credited the wholesale-related proceeds to each wholesale customer.benefit of customers.

In ~~March~~ 2014, Alabama Power and Georgia Power filed ~~additional~~ lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant 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 October 10, 2017, Alabama Power and Georgia Power filed additional 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 and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2015 through December 31, 2017. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of

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~~NOTES (continued)~~

~~Southern Company and Subsidiary Companies 2015 Annual Report~~

December 31, ~~2015~~2017 for any potential recoveries from the ~~additional~~pending lawsuits. The final outcome of these matters cannot be determined at this ~~time; however,~~time. However, Alabama Power and Georgia Power expect to credit any recoveries back for the benefit of customers in accordance with direction from their respective PSC and, therefore, no material impact on Southern Company's net income is expected.

On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant.

FERC Matters

Market-Based Rate Authority

Table of Contents Index to Financial Statements

NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.

The ultimate outcome of ~~this matter~~these matters cannot be determined at this time.

~~Retail~~

Regulatory Matters

Alabama Power

Rate RSE

~~In 2013, the Alabama PSC approved a revision to Rate RSE, effective for calendar year 2014. This revision established the WCE range of 5.75% to 6.21%~~ with an adjusting point of 5.98% and ~~provided~~ eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.

~~The~~ Rate RSE ~~increase~~adjustments for ~~2015~~any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If Alabama Power's actual retail return is above the allowed WCE range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.

Effective in January 2017, Rate RSE increased 4.48%, or $245 million annually. At December 31, 2017, Alabama Power's actual retail return was ~~3.49% or $181 million annually, and was effective January~~within the allowed WCE range. On December 1, ~~2015. On November 30, 2015,~~2017, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year ~~2016.~~2018. Projected earnings were within the specified ~~WCE~~ range; therefore, retail rates under Rate RSE remained unchanged for ~~2016.~~2018.

Rate CNP PPA

Alabama Power's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail ~~service under Rate CNP.~~service. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March ~~3, 2015,~~7, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate CNP PPA factor for billings for the period April 1, ~~2015~~2017 through March 31, ~~2016.~~2018. No adjustment to Rate CNP PPA is expected in ~~2016.~~2018. As of December 31, ~~2015,~~2017 and 2016, Alabama Power had an under recovered ~~certificated~~Rate CNP PPA balance of ~~$99~~$12 million and $142 million, respectively, which is included in deferred under recovered regulatory clause revenues in the balance sheet.

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power eliminated the under recovered balance in Rate CNP ~~Environmental allowed~~PPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," Alabama Power utilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2017.

Table of Contents Index to Financial Statements

NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Rate CNP Compliance

~~II-85~~

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~~NOTES (continued)~~

~~Southern Company and Subsidiary Companies 2015 Annual Report~~

annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital.

Revenues for Rate CNP Compliance, ~~increased 1.5%,~~as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on revenues or ~~$75~~net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million ~~annually,~~of its under recovered balance in Rate CNP Compliance to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, ~~2015.~~2017.

On December 5, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2018 the factors associated with Alabama Power's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered amounts associated with 2018 will be reflected in the 2019 filing. As of December 31, ~~2015,~~2017 and 2016, Alabama Power had ~~an under recovered compliance clause balance of $43 million, which is included in~~a deferred under recovered regulatory clause revenues ~~in the~~ balance ~~sheet.~~of $17 million and $9 million, respectively.

Integrated Resource Plan

See "Environmental Matters" herein for additional information regarding proposed and final EPA rules and regulations, including revisions to ELG for steam electric power plants and additional regulations of CCR and CO₂.

In July 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan (2016 IRP) including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). In August 2016, the Plant Mitchell and Plant Kraft units were retired and Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC.

Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.

The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in Georgia Power's 2019 base rate case.

The Georgia PSC also approved the Renewable Energy Development Initiative (REDI) to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.

In 2017, Georgia Power filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to be in operation by the end of 2019. Georgia Power also filed for and received approval to develop several solar generation projects to fulfill the approved self-build capacity.

In the 2016 IRP, the Georgia PSC also approved 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. On March 7, 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. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC in a future Georgia Power rate case.

Storm Damage Recovery

Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. Hurricanes Irma and Matthew caused significant damage to Georgia Power's transmission and distribution facilities during September 2017 and October 2016, respectively. The incremental restoration costs related to these hurricanes deferred in Georgia Power's regulatory

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asset for storm damage totaled approximately $260 million. At December 31, 2017, the total balance in Georgia Power's regulatory asset related to storm damage was $333 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements. See Note 3 to the financial statements under "Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information regarding Georgia Power's storm damage reserve.

Gulf Power

On April 4, 2017, the Florida PSC approved the 2017 Rate ~~ECR~~Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request in 2016 to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes. Gulf Power also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause.

~~Alabama~~The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to Gulf Power's base rates. Under the terms of the 2017 Rate Case Settlement Agreement, by March 1, 2018, Gulf Power ~~has established energy~~must identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to Gulf Power's base rates and $15.6 million to Gulf Power's environmental cost recovery rates ~~under Alabama~~effective beginning the first calendar month following approval.

The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through Gulf Power's ~~Rate ECR as approved~~fuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and Gulf Power will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the ~~Alabama PSC. Rates are~~parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.

The ultimate outcome of these matters cannot be determined at this time.

Mississippi Power

On February 7, 2018, Mississippi Power revised its annual projected PEP filing for 2018 to reflect the impacts of the Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an ~~estimate~~increased equity ratio of ~~future energy~~55%. The ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

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distribution services by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically.

With the exception of Atlanta Gas Light, 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 ~~current over~~billing factor will not have a significant effect on revenues or ~~under recovered balance. Revenues recognized under Rate ECR~~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 and ~~recorded on~~energy efficiency plans. See Note 1 to the financial statements under "Cost of Natural Gas" for additional information.

Regulatory Infrastructure Programs

Certain of Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs are 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. Initial program lengths range from nine to 10 years, with completion dates ranging from 2020 through 2025. The total expected investment under these programs for 2018 is $395 million.

Base Rate Cases

The Illinois Commerce Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commerce Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which Nicor Gas expects to file by the end of the second quarter 2018.

The ultimate outcome of these matters cannot be determined at this time.

Fuel Cost Recovery

The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for ~~the difference~~differences in actual recoverable fuel costs and amounts billed in current regulated rates. ~~The difference~~Accordingly, changes in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing ~~rates is required. Changes in the Rate ECR~~ factor will not have noa significant effect on Southern Company's revenues or net income, but will ~~impact~~affect cash flow. The traditional electric operating ~~cash flows. Currently, the Alabama PSC may approve billing rates~~companies continuously monitor their under ~~Rate ECR of up~~or over recovered fuel cost balances and make appropriate filings with their state PSCs to ~~5.910 cents per KWH. In December 2014, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2015 the Rate ECR factor of 2.681 cents per KWH.~~

On December 1, 2015, the Alabama PSC approved a decrease in Alabama Power’s Rate ECR factor from 2.681 to 2.030 cents per KWH, 6.7%, or $370 million annually, based upon projected billings, effective January 1, 2016. The approved decrease in the Rate ECR factor will have no significant effect on Southern Company's net income, but will decrease operating cash flows related toadjust fuel cost recovery rates as necessary.

See Note 1 to the financial statements under "Revenues" and Note 3 to the financial statements under "Regulatory Matters – Alabama Power – Rate ECR" and "Regulatory Matters – Georgia Power – Fuel Cost Recovery" for additional information.

Kemper County Energy Facility

The Kemper County energy facility was approved by the Mississippi PSC as an IGCC facility in ~~2016 when compared~~the 2010 CPCN proceedings, subject to ~~2015.~~a construction cost cap of $2.88 billion, net of $245 million of the Initial DOE Grants and excluding the Cost Cap Exceptions. The combined cycle and associated common facilities portions of the Kemper County energy facility were placed in service in August 2014. In December 2015, the Mississippi PSC issued the In-Service Asset Rate Order, authorizing rates that provided for the recovery of approximately $126 million annually related to the assets previously placed in service.

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On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. At the time of project suspension, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants. In the aggregate, Mississippi Power had incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine.

Under the Kemper Settlement Agreement, retail customer rates will ~~return to 2.681 cents per KWH in 2017~~reflect a reduction of approximately $26.8 million annually and ~~5.910 cents per KWH~~include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 ~~absent~~or at any future date. On February 12, 2018, Mississippi Power made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) Mississippi Power to file a ~~further order from~~reserve margin plan with the ~~Alabama PSC.~~Mississippi PSC by August 2018.

~~Alabama Power's over recovered fuel~~During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power has begun efforts to dispose of or abandon the mine and gasifier-related assets.

Total pre-tax charges to income related to the Kemper County energy facility were $3.4 billion ($2.4 billion after tax) for the year ended December 31, ~~2015 totaled $238 million as compared to $47 million at~~2017. In the aggregate, since the Kemper County energy facility project started, Mississippi Power has incurred charges of $6.2 billion ($4.1 billion after tax) through December 31, ~~2014. At December 31, 2015, $238 million~~2017.

As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is ~~included~~resolved, subject to any future legal challenges.

See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.

Litigation

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other ~~regulatory liabilities, current.~~things, Southern Company as a defendant. The over recovered fuel costs at December 31, 2014 are included in deferred over recovered regulatory clause revenues. These classifications are based on estimates, which include such factors as weather, generation availability,individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy ~~demand,~~facility and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the ~~price of energy. A change~~Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of ~~these factors~~motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the

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Construction Program

Overview

The subsidiary companies of Southern Company 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, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. 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 their regulated rates. The Southern Company system's construction program is currently estimated to total approximately $9.4 billion, $9.3 billion, $8.4 billion, $7.0 billion, and $6.9 billion for 2018, 2019, 2020, 2021, and 2022, respectively.

The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs). See Note 3 to the financial statements under "Nuclear Construction" for additional information. See Note 12 to the financial statements under "Southern Power" for additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities. See Note 3 to the financial statements under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" for additional information regarding infrastructure improvement programs at the natural gas distribution utilities.

Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.

Nuclear Construction

Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In the first quarter 2016, Westinghouse delivered to the Vogtle Owners a total of $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement.

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On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share was approximately $1.7 billion. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, Georgia Power, the other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of Georgia Power, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and Georgia Power and the other Vogtle Owners surrendered the Westinghouse Letters of Credit.

On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, 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 (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power 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 because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. 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.

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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 nuclear construction projects certified by the Georgia PSC. 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. As of December 31, 2017, Georgia Power had recovered approximately $1.6 billion of financing costs. On January 30, 2018, Georgia Power filed to decrease the NCCR tariff by approximately $50 million, effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, the Customer Refunds ordered by the Georgia PSC aggregating approximately $188 million, and the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and will be paid in three installments of $25 to each retail customer no later than the third quarter 2018.

On December 20, 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. On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying 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 $5.680 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 $5.680 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 Customer Refunds) is 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 $20 million in 2016 and $25 million in 2017 and are estimated to have negative earnings impacts of approximately $120 million in 2018 and an aggregate of $585 million from 2019 to 2022. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Georgia PSC reserve the right to reconsider the decision to continue construction.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. Georgia Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of operations, financial condition, and liquidity.

The IRS allocated PTCs to each of Plant Vogtle Units 3 and 4, which originally required the applicable unit to be placed in service before 2021. Under the Bipartisan Budget Act of 2018, Plant Vogtle Units 3 and 4 continue to qualify for PTCs. The nominal value of Georgia Power's portion of the PTCs is approximately $500 million per unit.

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In its January 11, 2018 order, the Georgia PSC also approved $542 million of capital costs incurred during the seventeenth VCM reporting period (January 1, 2017 to June 30, 2017). The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. Georgia Power expects to file its eighteenth VCM report on February 28, 2018 requesting approval of approximately $450 million of construction capital costs (before payments received under the Guarantee Settlement Agreement and the Customer Refunds) incurred from July 1, 2017 through December 31, 2017. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $4.8 billion as of December 31, 2017, or $3.3 billion net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.

The ultimate outcome of these matters cannot be determined at this time.

Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service dates of November 2021 and November 2022, respectively, is as follows:



	(in billions)
Project capital cost forecast	$	7.3
Net investment as of December 31, 2017	(3.4		)
Remaining estimate to complete	$	3.9

Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.

The ultimate outcome of these matters cannot be determined at this time.

Other Matters

As of December 31, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

The ultimate outcome of these matters cannot be determined at this time.

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Income Tax Matters

Federal Tax Reform Legislation

See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.

The ultimate outcome of these matters cannot be determined at this time.

Bonus Depreciation

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Tax Credits

The Tax Reform Legislation retained the renewable energy incentives that were included in the PATH Act. The PATH Act allows for 30% ITC for solar projects that commence construction by December 31, 2019; 26% ITC for solar projects that commence construction in 2020; 22% ITC for solar projects that commence construction in 2021; and a permanent 10% ITC for solar projects that commence construction on or after January 1, 2022. In addition, the PATH Act allows for 100% PTC for wind projects that commenced construction in 2016; 80% PTC for wind projects that commenced construction in 2017; 60% PTC for wind projects that commence construction in 2018; and 40% PTC for wind projects that commence construction in 2019. Wind projects commencing construction after 2019 will not be entitled to any PTCs. The Company has received ITCs and PTCs in connection with investments in solar, wind, and biomass facilities primarily at Southern Power and Georgia Power. See Note 1 to the financial statements under "Income and Other Taxes" and Note 5 to the financial statements under "Current and Deferred Income Taxes – Tax Credit Carryforwards" for additional information regarding the utilization and amortization of credits and the tax benefit related to basis differences.

Southern Power

In September 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $55 million related to certain changes in state apportionment rates and net operating loss carryforward utilization that will be recorded in the first quarter 2018. Southern Power is pursuing the sale of a 33% equity interest in the newly-formed holding company owning these solar assets. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. 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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as standards for air, water, land, and protection of other natural resources, 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 predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

In 2016, the SEC began conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper County energy facility. On November 30, 2017, the SEC staff notified Southern Company that it had concluded its investigation with no recommended enforcement action.

Litigation

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Southern Company and Subsidiary Companies 2017 Annual Report

Investments in Leveraged Leases

The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. In the last six months of 2017, the financial and operational performance of one of the lessees and the associated generation assets has raised significant concerns about the short-term ability of the generation assets to produce cash flows sufficient to support ongoing operations and the lessee's contractual obligations and its ability to make the remaining semi-annual lease payments to the Southern Holdings subsidiary beginning in June 2018. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If the June 2018 (or any ~~recovery or return~~future) lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of ~~fuel costs.~~the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable which had a balance of approximately $86 million as of December 31, 2017. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of December 31, 2017. 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, including the lease payment due in June 2018. The ultimate outcome of this matter cannot be determined at this time.

~~Rate NDR~~

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~~Based on~~

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Natural Gas Storage

A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At December 31, 2017, the facility's property, plant, and equipment had a net book value of $112 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the ~~Alabama PSC, Alabama Power maintains~~Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.

The cavern continues to maintain its pressures and overall structural integrity. Southern Company Gas intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with Southern Company Gas' annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a ~~reserve for~~significant impact on Southern Company's financial statements.

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 Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and ~~maintenance~~related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.

Utility Regulation

Southern Company's traditional electric operating companies and natural gas distribution utilities, which collectively comprised approximately 86% of Southern Company's total operating revenues for 2017, are subject to retail regulation by their respective state PSCs or other applicable state regulatory agencies and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional electric operating companies and the natural gas distribution utilities are permitted to charge customers based on allowable costs, including a reasonable ROE. As a result, the traditional electric operating companies and the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional electric operating companies and the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.

As reflected in Note 1 to ~~cover~~the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.

Kemper County Energy Facility Rate Recovery

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Southern Company and Subsidiary Companies 2017 Annual Report

to the Kemper County energy facility of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.

As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as Mississippi Power's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper County energy facility, the estimated construction costs and project completion date are no longer considered significant accounting estimates.

As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges, and no longer represents a critical accounting estimate.

See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.

Accounting for Income Taxes

Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of the Company's current financial position and result of operations, including currently available information about future years, to estimate when future taxable income will be realized.

Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States utilize various formulas to calculate the apportionment of taxable income, primarily using sales, assets, or payroll within the jurisdiction compared to the consolidated totals. In addition, each state varies as to whether a stand-alone, combined, or unitary filing methodology is required. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. The apportionments and methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on Southern Company's financial statements.

Given the significant judgment involved in estimating NOL and tax credit carryforwards and multi-state apportionments for all subsidiaries, Southern Company considers state deferred income tax liabilities and assets to be critical accounting estimates.

Federal Tax Reform Legislation

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Southern Company and Subsidiary Companies 2017 Annual Report

to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Regulatory Matters" and "Current and Deferred Income Taxes," respectively, for additional information.

Asset Retirement Obligations

The liability for AROs primarily relates to ~~its~~facilities that are subject to the CCR Rule, principally ash ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric transmission and distribution ~~facilities.~~ facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded as the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.

The ~~order approves~~cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the traditional electric operating companies will continue to periodically update these cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.

Given the significant judgment involved in estimating AROs, Southern Company considers the liabilities for AROs to be critical accounting estimates.

Pension and Other Postretirement Benefits

Southern Company's calculation of pension and other postretirement benefits expense is dependent on a ~~separate monthly Rate NDR~~number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.

Key elements in determining Southern Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, Southern Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. Beginning in 2016, Southern Company adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost

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Southern Company and Subsidiary Companies 2017 Annual Report

component of net periodic pension and other postretirement benefit plan expense decreased by approximately $96 million in 2016.



Change in Assumption	Increase/(Decrease) in Total Benefit Expense for 2018	Increase/(Decrease) in Projected Obligation for Pension Plan at December 31, 2017	Increase/(Decrease) in Projected Obligation for Other Postretirement Benefit Plans at December 31, 2017
	(in millions)
25 basis point change in discount rate	$40/$(38)	$504/$(476)	$68/$(65)
25 basis point change in salaries	$24/$(23)	$119/$(115)	$–/$–
25 basis point change in long-term return on plan assets	$33/$(33)	N/A	N/A

N/A – Not applicable

See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.

Goodwill and Other Intangible Assets

Derivatives and Hedging Activities

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Southern Company and Subsidiary Companies 2017 Annual Report

the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);

events specific to a given counterparty; and

the impact of Southern Company's nonperformance risk on its liabilities.

Contingent Obligations

Recently Issued Accounting Standards

Revenue

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers ~~consisting~~at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of ~~two components.~~ revenue and the related cash flows arising from contracts with customers.

The ~~first~~new standard is effective for reporting periods beginning after December 15, 2017. Southern Company applied the modified retrospective method of adoption effective January 1, 2018. Southern Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.

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Southern Company and Subsidiary Companies 2017 Annual Report

Leases

In February 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. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company will adopt the new standard effective January 1, 2019.

Other

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. Southern Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.

On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is ~~intended to establish~~eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and ~~maintain a reserve balance for future storms~~the other components of net periodic pension and ~~is an on-going part~~postretirement benefit costs in the income statement. The capitalization of ~~customer billing. The second~~only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. Southern Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.

On August 28, 2017, the ~~Rate NDR charge~~FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is ~~intended~~effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.

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Southern Company and Subsidiary Companies 2017 Annual Report

FINANCIAL CONDITION AND LIQUIDITY

Overview

Earnings in all periods presented were negatively affected by charges associated with the Kemper IGCC; however, Southern Company's financial condition remained stable at December 31, 2017.

The Southern Company system's cash requirements primarily consist of ~~any~~funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. The Southern Company system's capital expenditures and other investing activities include investments to meet projected long-term demand requirements, including to build new electric generation facilities, to maintain existing ~~deferred storm-related operations~~electric generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing electric generating units, to expand and ~~maintenance costs~~improve electric transmission and ~~any future reserve deficits over~~distribution facilities, to update and expand natural gas distribution systems, and for restoration following major storms. Operating cash flows provide a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate asubstantial portion of the ~~NDR~~Southern Company system's cash needs. For the three-year period from 2018 through 2020, Southern Company's projected common stock dividends, capital expenditures, and debt maturities are expected to ~~reliability-related~~exceed operating cash flows. Southern Company plans to finance future cash needs in excess of its operating cash flows primarily by accessing borrowings from financial institutions and through debt and equity issuances in the capital markets. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.

Southern Company's investments in the qualified pension plans and the nuclear decommissioning trust funds increased in value as of December 31, 2017 as compared to December 31, 2016. No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plans are anticipated during 2018. See "Contractual Obligations" herein and Notes 1 and 2 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.

Net cash provided from operating activities in 2017 totaled $6.4 billion, an increase of $1.5 billion from 2016. The increase in net cash provided from operating activities was primarily due to increases of $1.2 billion related to operating activities of Southern Company Gas, which was acquired on July 1, 2016, and $1.0 billion related to voluntary contributions to the qualified pension plan in 2016, partially offset by the timing of vendor payments. Net cash provided from operating activities in 2016 totaled $4.9 billion, a decrease of $1.4 billion from 2015. Significant changes in operating cash flow for 2016 as compared to 2015 included approximately $1.0 billion of voluntary contributions to the qualified pension plan in 2016 and a $1.2 billion increase in unutilized ITCs and PTCs.

Net cash used for investing activities in 2017, 2016, and 2015 totaled $7.2 billion, $20.0 billion, and $7.3 billion, respectively. The cash used for investing activities in 2017 was 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, capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions. The cash used for investing activities in 2016 was primarily due to the closing of the Merger, the acquisition of PowerSecure, Southern Company Gas' investment in SNG, the traditional electric operating companies' construction of electric generation, transmission, and distribution facilities and installation of equipment at electric generating facilities to comply with environmental standards, and Southern Power's acquisitions and construction of renewable facilities and a natural gas facility. The cash used for investing activities in 2015 was primarily due to the traditional electric operating companies' gross property additions for installation of equipment at electric generating facilities to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, Southern Power's acquisitions of solar facilities, and purchases of nuclear fuel.

Significant balance sheet changes in 2017 included decreases of $7.3 billion and $0.8 billion in accumulated deferred income taxes and deferred charges related to income taxes, respectively, and an increase of $7.0 billion in deferred credits related to

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income taxes primarily resulting from the impacts of the Tax Reform Legislation; an increase of $1.4 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, Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions, largely offset by the $2.8 billion write-down of the gasification portions of the Kemper County energy facility and payments of $1.7 billion received by Georgia Power under the Guarantee Settlement Agreement; an increase of $3.1 billion in long-term debt (including amounts due within one year) primarily to fund the Southern Company system's continuous construction programs and for general corporate purposes; and a decrease of $1.1 billion in total stockholder's equity primarily related to the Kemper County energy facility charges, partially offset by the issuance of additional shares of common stock. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" and "Financing Activities" herein and Note 3 to the financial statements under "Nuclear Construction" and "Kemper County Energy Facility" for additional information.

At the end of 2017, the market price of Southern Company's common stock was $48.09 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.99 per share, representing a market-to-book value ratio of 201%, compared to $49.19, $25.00, and 197%, respectively, at the end of 2016.

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 the Company's stock plans, private placements, or public offerings. The amount and timing of additional equity and debt issuances in 2018, 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 any potential sale of a 33% equity interest in a newly-formed holding company that owns substantially all of its solar assets, if completed. Southern Company Gas also plans to utilize the proceeds from the pending asset sales of two of its natural gas distribution utilities. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See FUTURE EARNINGS POTENTIAL – "General" herein for additional information.

In addition, in 2014, Georgia Power entered into the 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. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of December 31, 2017, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.

On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note 3 to the financial statements under "Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

The issuance of securities by the traditional electric operating companies and Nicor Gas is generally subject to the approval of the applicable state PSC or other applicable state regulatory agency. The issuance of all securities by Mississippi Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company and certain of its subsidiaries file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as

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well as the securities registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

Southern Company, each traditional electric operating company, and Southern Power generally obtain financing separately without credit support from any affiliate. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company in the Southern Company system.

See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.

As of December 31, 2017, Southern Company's current liabilities exceeded current assets by $3.5 billion, due to $3.9 billion of long-term debt that is due within one year (comprised of approximately $1.0 billion at the parent company, $0.9 billion at Georgia Power, $1.0 billion at Mississippi Power, $0.8 billion at Southern Power, and $0.2 billion at Southern Company Gas) and $2.4 billion of notes payable (comprised of approximately $0.6 billion at the parent company, $0.2 billion at Georgia Power, $0.1 billion at Southern Power, and $1.5 billion at Southern Company Gas). 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.

At December 31, 2017, Southern Company and its subsidiaries had approximately $2.1 billion of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2017 were as follows:



	Expires												Executable Term Loans				Expires Within One Year
Company	2018		2019		2020		2022		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)
Southern Company^(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—	$	—	$	—	$	—
Alabama Power	35		—		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	30		25		225		—		280		280		45		—		20		10
Mississippi Power	100		—		—		—		100		100		—		—		—		100
Southern Power Company^(b)	—		—		—		750		750		728		—		—		—		—
Southern Company Gas^(c)	—		—		—		1,900		1,900		1,890		—		—		—		—
Other	30		—		—		—		30		30		20		—		20		10
Southern Company Consolidated	$	195	$	25	$	725	$	7,200	$	8,145	$	8,094	$	65	$	—	$	40	$	155


(a)	Represents the Southern Company parent entity.


(b)	Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $19 million remains unused at December 31, 2017.


(c)	Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.

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Southern Company and Subsidiary Companies 2017 Annual Report

Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement with $1.4 billion and $500 million currently allocated to Southern Company Gas Capital and Nicor Gas, respectively, maturing in 2022. Pursuant to the new multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. In September 2017, Alabama Power also amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020. In November 2017, Gulf Power amended $195 million of its multi-year credit arrangements to extend the maturity dates from 2017 and 2018 to 2020 and Mississippi Power amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018.

Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, 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 December 31, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

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, and Nicor Gas. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of December 31, 2017 was approximately $1.5 billion as compared to $1.9 billion at December 31, 2016. In addition, at December 31, 2017, the traditional electric operating companies had approximately $714 million of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to December 31, 2017, $50 million of these revenue bonds of Mississippi Power which were in a long-term interest rate mode were remarketed in an index rate mode.

At December 31, 2017, Pivotal Utility Holdings, Inc., a subsidiary of Southern Company Gas, had $200 million of gas facility revenue bonds outstanding. The Elizabethtown Gas asset sale agreement requires that bonds representing $180 million of the total that are currently eligible for redemption at par be redeemed on or prior to consummation of the sale. See FUTURE EARNINGS POTENTIAL – "General" herein and Note 6 to the financial statements under "Gas Facility Revenue Bonds" for additional information.

Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas 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.

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Southern Company and Subsidiary Companies 2017 Annual Report

Details of short-term borrowings were as follows:



	Short-term Debt at the End of the Period				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)
December 31, 2017:
Commercial paper	$	1,832	1.8	%	$	2,117	1.3	%	$	2,946
Short-term bank debt	607		2.3	%	555		2.1	%	1,020
Total	$	2,439	1.9	%	$	2,672	1.5	%
December 31, 2016:
Commercial paper	$	1,909	1.1	%	$	976	0.8	%	$	1,970
Short-term bank debt	123		1.7	%	176		1.7	%	500
Total	$	2,032	1.1	%	$	1,152	1.1	%
December 31, 2015:
Commercial paper	$	740	0.7	%	$	842	0.4	%	$	1,563
Short-term bank debt	500		1.4	%	444		1.1	%	795
Total	$	1,240	0.9	%	$	1,286	0.5	%


(*)	Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2017, 2016, and 2015.

In addition to the short-term borrowings of Southern Power Company included in the table above, at December 31, 2016 and 2015, Southern Power Company subsidiaries had credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. The Project Credit Facilities were fully repaid in January 2017. For the year ended December 31, 2016, the Project Credit Facilities had a maximum amount outstanding of $828 million and an average amount outstanding of $566 million at a weighted average interest rate of 2.1% and had total amounts outstanding of $209 million at a weighted average interest rate of 2.1% at December 31, 2016. For the year ended December 31, 2015, the Project Credit Facilities had a maximum amount outstanding of $137 million and an average amount outstanding of $13 million at a weighted average interest rate of 2.0% and had total amounts outstanding of $137 million at a weighted average interest rate of 2.0% at December 31, 2015.

The 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.

Financing Activities

During 2017, Southern Company issued approximately 14.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $659 million.

In addition, during the second and third quarters of 2017, Southern Company issued a total of approximately 2.7 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $134 million, net of $1.1 million in fees and commissions.

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Southern Company and Subsidiary Companies 2017 Annual Report

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the year ended December 31, 2017:



Company	Senior Note Issuances		Senior Note Maturities and Redemptions		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)	$	300	$	400	$	—	$	—	$	950		$	400
Alabama Power	1,100		525		—		36		—			—
Georgia Power	1,350		450		65		65		370			17
Gulf Power	300		85		—		—		6			—
Mississippi Power	—		35		—		—		40			962
Southern Power	525		500		—		—		43			18
Southern Company Gas^(c)	450		—		—		—		400			22
Other	—		—		—		—		—			15
Elimination^(d)	—		—		—		—		(40		)	(602		)
Southern Company Consolidated	$	4,025	$	1,995	$	65	$	101	$	1,769		$	832


(a)	Includes reductions in capital lease obligations resulting from cash payments under capital leases.


(b)	Represents the Southern Company parent entity.


(c)	The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas.


(d)	Includes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements.

Except as otherwise described herein, Southern Company and its subsidiaries used 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 and, for the subsidiaries, their continuous construction programs.

In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.

In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057 and $300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR.

Also in August 2017, Southern Company repaid at maturity $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes.

In November 2017, Southern Company issued $450 million aggregate principal amount of Series 2017B 5.25% Junior Subordinated Notes due December 1, 2077.

In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The majority of the proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of Alabama Power's 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of Alabama Power's 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of Alabama Power's 5.83% Class A Preferred Stock.

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Southern Company and Subsidiary Companies 2017 Annual Report

loan of $100 million, with a maturity date of June 28, 2018, which was amended in August 2017 to extend the maturity date to October 26, 2018. These loans bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank.

Subsequent to December 31, 2017, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.

As reflected in the table above under other long-term debt issuances, in September 2017, Georgia Power also issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.

In March 2017, Gulf Power extended the maturity of its $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.

A portion of the proceeds of Gulf Power's senior note issuances was used in June 2017 to redeem 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.

In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.

In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate term loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018.

Credit Rating Risk

At December 31, 2017, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a ~~part~~result of ~~an annual budget process~~a credit rating downgrade.

The maximum potential collateral requirements under these contracts at December 31, 2017 were as follows:



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	40
At BBB- and/or Baa3	$	665
At BB+ and/or Ba1^(*)	$	2,390


(*)	Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 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

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Southern Company and Subsidiary Companies 2017 Annual Report

impact the cost at which they do so.

On March 1, 2017, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Ba1 from Baa3.

On March 20, 2017, Moody's revised its rating outlook for Georgia Power from stable to negative.

On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the traditional electric operating companies, Southern Power, Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.

On March 30, 2017, Fitch Ratings, Inc. placed the ratings of Southern Company, Georgia Power, and Mississippi Power on rating watch negative.

On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade. On September 21, 2017, Moody's revised its rating outlook for Mississippi Power from under review to stable.

On January 19, 2018, Moody's revised its rating outlooks for Southern Company and Alabama Power from stable to negative.

While it is unclear how the credit rating agencies, the FERC, and relevant state regulatory bodies may respond to 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. Absent actions by Southern Company and its subsidiaries to mitigate the resulting impacts, which, among other alternatives, could include adjusting capital structure and/or monetizing regulatory assets, the credit ratings of Southern Company and certain of its subsidiaries could be negatively affected. See Note 3 to the financial statements for additional information related to state PSC or other regulatory agency actions related to the Tax Reform Legislation.

Market Price Risk

The Southern Company system is 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, the applicable company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the ~~following~~remaining exposures pursuant to the applicable 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.

To mitigate future exposure to a change in interest rates, Southern Company and certain of its subsidiaries enter into derivatives that have been designated as hedges. Derivatives that have been designated as hedges outstanding at December 31, 2017 have a notional amount of $3.7 billion and are intended to mitigate interest rate volatility related to existing fixed and floating rate obligations. The weighted average interest rate on $6.3 billion of long-term variable interest rate exposure at December 31, 2017 was 2.43%. If Southern Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $63 million at December 31, 2017. See Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements for additional information.

Southern Power Company had foreign currency denominated debt of €1.1 billion at December 31, 2017. Southern Power Company has mitigated its exposure to foreign currency exchange rate risk through the use of foreign currency swaps converting all interest and principal payments to fixed-rate U.S. dollars.

Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional electric operating companies and natural gas distribution utilities continue to have limited exposure to market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. In addition, Southern Power's exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional electric operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases; however, a significant portion of contracts are priced at market. The traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies. Southern Company had no material change in market risk exposure for the year ended December 31, 2017 when compared to the year ended December 31, 2016.

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Southern Company and Subsidiary Companies 2017 Annual Report

The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows:



	2017 Changes			2016 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	41		$	(213	)
Acquisitions	—			(54		)
Contracts realized or settled	(8		)	141
Current period changes^(a)	(196		)	171
Contracts outstanding at the end of the period, assets (liabilities), net^(b)	$	(163	)	$	45


(a)	Current period changes also include the changes in fair value of new contracts entered into during the period, if any.


(b)	Excludes premium and intrinsic value associated with weather derivatives of $11 million at December 31, 2017 and includes premium and intrinsic value associated with weather derivatives of $4 million at December 31, 2016.

The net hedge volumes of energy-related derivative contracts were 621 million mmBtu and 500 million mmBtu for the years ended December 31, 2017 and 2016, respectively.

For the traditional electric operating companies and Southern Power, the weighted average swap contract cost above or ~~during~~(below) market prices was approximately $0.15 per mmBtu as of December 31, 2017 and $(0.05) per mmBtu as of December 31, 2016. The majority of the ~~current~~natural gas hedge gains and losses are recovered through the traditional electric operating companies' fuel cost recovery clauses.

At December 31, 2017 and 2016, substantially all of the Southern Company system's energy-related derivative contracts were designated as regulatory hedges and were related to the applicable company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. 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 and were not material for any year presented.

The Southern Company system uses exchange-traded market-observable contracts, which are categorized as Level 1 of the fair value hierarchy, and over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 10 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts at December 31, 2017 were as follows:



	Fair Value Measurements
	December 31, 2017
	Total Fair Value			Maturity
	Total Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	(148	)	$	(71	)	$	(59	)	$	(18	)
Level 2	(15		)	(30		)	13			2
Level 3	—			—			—			—
Fair value of contracts outstanding at end of period	$	(163	)	$	(101	)	$	(46	)	$	(16	)

The Southern Company system is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. The Southern Company system only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Southern Company system does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements.

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Southern Company and Subsidiary Companies 2017 Annual Report

With the exception of Southern Company Gas' subsidiary, Atlanta Gas Light, and the Southern Company Gas wholesale gas services business, the Southern Company system is not exposed to concentrations of credit risk. Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 15 natural gas marketers in Georgia responsible for the retail sale of natural gas to end-use customers in Georgia. For 2017, the four largest natural gas marketers based on customer count accounted for 19% of Southern Company Gas' adjusted operating margin. Southern Company Gas' wholesale gas services business has a concentration of credit risk for services it provides to its counterparties as measured by its 30-day receivable exposure plus forward exposure. At December 31, 2017, Southern Company Gas' wholesale gas services business' top 20 counterparties represented approximately 48%, or $203 million, of its total counterparty exposure and had a weighted average S&P equivalent credit rating of A-, all of which is consistent with the prior year.

Southern Company performs periodic reviews of its leveraged lease transactions, both domestic and international, and the creditworthiness of the lessees, including a review of the value of the underlying leased assets and the credit ratings of the lessees. Southern Company's domestic lease transactions generally do not have any credit enhancement mechanisms; however, the lessees in its international lease transactions have pledged various deposits as additional security to secure the obligations. The lessees in the Company's international lease transactions are also required to provide additional collateral in the event of a credit downgrade below a certain level.

Capital Requirements and Contractual Obligations

The Southern Company system's construction program is currently estimated to total approximately $9.4 billion for 2018, $9.3 billion for 2019, $8.4 billion for 2020, $7.0 billion for 2021, and $6.9 billion for 2022. These amounts include expenditures of approximately $1.2 billion, $1.0 billion, $0.9 billion, $0.7 billion, and $0.4 billion for the construction of Plant Vogtle Units 3 and 4 in 2018, 2019, 2020, 2021, and 2022, respectively, and an average of approximately $1.3 billion per year for ~~identified unbudgeted reliability-related~~2018 through 2022 for Southern Power's planned expenditures for plant acquisitions and placeholder growth. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $1.1 billion, $0.3 billion, $0.4 billion, $0.5 billion, and $0.5 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO₂ emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and " – Global Climate Issues" herein for additional information.

The traditional electric operating companies also anticipate costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in the Company's ARO liabilities. These costs, which could change as the Southern Company system continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be approximately $0.3 billion, $0.3 billion, $0.4 billion, $0.5 billion, and $0.4 billion for 2018, 2019, 2020, 2021, and 2022, respectively. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" 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 the 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; storm impacts; and the cost of capital. In addition, there can be no assurance that ~~are incurred. Accruals~~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 execute its growth strategy. See Note 12 to the financial statements under "Southern Power" for additional information regarding Southern Power's plant acquisitions.

In addition, the construction program includes the development and construction of new electric generating facilities with designs that have not been ~~designated~~previously constructed, which may result in revised estimates during construction. The ability to control costs and avoid cost 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 and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance. See Note 3 to the financial statements under "Nuclear Construction" for information regarding additional factors that may impact construction expenditures.

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Southern Company and Subsidiary Companies 2017 Annual Report

As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under "Nuclear Decommissioning."

In addition, as discussed in Note 2 to the financial statements, the Southern Company system provides postretirement benefits to the majority of its employees and funds trusts to the extent required by PSCs, other applicable state regulatory agencies, or the FERC.

Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred stock dividends, leases, unrecognized tax benefits, pipeline charges, storage capacity, gas supply, asset management agreements, other purchase commitments, and trusts are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 11 to the financial statements for additional information.

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Southern Company and Subsidiary Companies 2017 Annual Report

Contractual Obligations

The Southern Company system's contractual obligations at December 31, 2017 were as follows:



	2018		2019- 2020		2021- 2022		After 2022		Total
	(in millions)
Long-term debt^(a) —
Principal	$	3,865	$	6,293	$	5,206	$	32,610	$	47,974
Interest	1,782		3,286		2,793		27,535		35,396
Preferred stock dividends of subsidiaries^(b)	16		33		33		—		82
Financial derivative obligations^(c)	493		198		37		5		733
Operating leases^(d)	149		232		178		968		1,527
Capital leases^(d)	39		43		20		232		334
Unrecognized tax benefits^(e)	18		—		—		—		18
Pipeline charges, storage capacity, and gas supply^(f)	813		968		714		2,294		4,789
Asset management agreements^(g)	9		6		—		—		15
Purchase commitments—
Capital^(h)	9,016		16,905		12,749		—		38,670
Fuel⁽ⁱ⁾	3,156		3,573		1,927		5,588		14,244
Purchased power^(j)	424		884		886		3,716		5,910
Other^(k)	407		713		434		2,745		4,299
Trusts —
Nuclear decommissioning^(l)	5		11		11		94		121
Pension and other postretirement benefit plans^(m)	137		275		—		—		412
Total	$	20,329	$	33,420	$	24,988	$	75,787	$	154,524

(a)

All amounts are reflected based on final maturity dates except for amounts related to FFB borrowings and certain revenue bonds. As it relates to the FFB borrowings, the final maturity date is February 20, 2044; however, principal amortization is reflected beginning in 2020. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" and "Securities Due Within One Year" for additional information. Southern Company and its subsidiaries plan to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of December 31, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).


(b)	Represents preferred stock of subsidiaries. Preferred stock does not mature; therefore, amounts are provided for the next five years only.


(c)	See Notes 1 and 11 to the financial statements.


(d)	Excludes PPAs that are accounted for as leases and included in "Purchased power."


(e)	See Note 5 to the financial statements under "Unrecognized Tax Benefits" for additional information.

(f)

Includes charges recoverable through a natural gas cost recovery mechanism, or alternatively billed to marketers selling retail natural gas, and demand charges associated with Southern Company Gas' wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas' gas marketing services of 35 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2017 and valued at $101 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations.


(g)	Represents fixed-fee minimum payments for asset management agreements associated with wholesale gas services.

(h)

The Southern Company system provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs which are reflected in "Fuel" and "Other," respectively. At December 31, 2017, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" herein for additional information.

(i)

Primarily includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2017.


(j)	Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities.


(k)	Includes LTSAs, contracts for the procurement of limestone, contractual environmental remediation liabilities, and operation and maintenance agreements. LTSAs include price escalation based on inflation indices.

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Southern Company and Subsidiary Companies 2017 Annual Report

(l)

Projections of nuclear decommissioning trust fund contributions for Plant Hatch and Plant Vogtle Units 1 and 2 are based on the 2013 ARP for Georgia Power. Alabama Power also has external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. See Note 1 to the financial statements under "Nuclear Decommissioning" for additional information.

(m)

The Southern Company system forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Southern Company anticipates no mandatory contributions to the qualified pension plans during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from corporate assets of Southern Company's subsidiaries. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from corporate assets of Southern Company's subsidiaries.

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

Southern Company's 2017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the wholesale business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plans, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates of construction projects, completion of announced acquisitions or dispositions, filings with state and federal regulatory authorities, impacts of the Tax Reform Legislation, federal and state income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be ~~used~~identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to ~~offset storm charges. Additional accruals~~differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

the ~~NDR will enhance Alabama Power's~~uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of Southern Company and its subsidiaries;

current and future litigation or regulatory investigations, proceedings, or inquiries;

the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;

variations in demand for electricity and natural gas, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

available sources and costs of natural gas and other fuels;

limits on pipeline capacity;

transmission constraints;

effects of inflation;

the ability to ~~deal~~control costs and avoid cost overruns during the development, construction, and operation of facilities, which include the development and construction of generating facilities with designs that have not been previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance;

the ability to construct facilities in accordance with the ~~financial effects~~requirements of permits and licenses (including satisfaction of NRC requirements), to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;

investment performance of the Southern Company system's employee and retiree benefit plans and nuclear decommissioning trust funds;

advances in technology;

ongoing renewable energy partnerships and development agreements;

state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;

the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural ~~disasters, promote system reliability,~~gas distribution and ~~offset costs retail customers would otherwise bear.~~storage facilities and the successful performance of necessary corporate functions;

~~As revenue from the Rate NDR charge is recognized, an equal amount~~

Table of ~~operations~~Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and ~~maintenance expenses~~Subsidiary Companies 2017 Annual Report

legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;

litigation related to the ~~NDR~~Kemper County energy facility;

the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;

the inherent risks involved in transporting and storing natural gas;

the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;

internal restructuring or other restructuring options that may be pursued;

potential business strategies, including acquisitions or dispositions of assets or businesses, including the proposed disposition by a wholly-owned subsidiary of Southern Company Gas of Elizabethtown Gas and Elkton Gas and the potential sale of a 33% equity interest in substantially all of Southern Power's solar assets, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;

the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected and the possibility that costs related to the integration of Southern Company and Southern Company Gas will ~~also~~ be ~~recognized. As a result,~~ greater than expected;

the ~~Rate NDR charge will not have an~~ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;

the ability to obtain new short- and long-term contracts with wholesale customers;

the direct or indirect effect on ~~net income but will impact operating cash flows.~~

~~Environmental Accounting Order~~

~~Based on an order~~the Southern Company system's business resulting from ~~the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance~~cyber intrusion or physical attack and the ~~unrecovered costs, associated~~threat of physical attacks;

interest rate fluctuations and financial market conditions and the results of financing efforts;

changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;

the ability of Southern Company's electric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;

the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;

impairments of goodwill or long-lived assets;

the effect of accounting pronouncements issued periodically by standard-setting bodies; and

other factors discussed elsewhere herein and in other reports filed by Southern Company from time to time with ~~site removal~~the SEC.

Southern Company expressly disclaims any obligation to update any forward-looking statements.

Table of Contents Index to Financial Statements

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2017, 2016, and ~~closure associated with future unit retirements caused by environmental regulations. These costs~~2015

Southern Company and Subsidiary Companies 2017 Annual Report



	2017			2016			2015
	(in millions)
Operating Revenues:
Retail electric revenues	$	15,330		$	15,234		$	14,987
Wholesale electric revenues	2,426			1,926			1,798
Other electric revenues	681			698			657
Natural gas revenues	3,791			1,596			—
Other revenues	803			442			47
Total operating revenues	23,031			19,896			17,489
Operating Expenses:
Fuel	4,400			4,361			4,750
Purchased power	863			750			645
Cost of natural gas	1,601			613			—
Cost of other sales	513			260			—
Other operations and maintenance	5,481			5,240			4,416
Depreciation and amortization	3,010			2,502			2,034
Taxes other than income taxes	1,250			1,113			997
Estimated loss on Kemper IGCC	3,362			428			365
Total operating expenses	20,480			15,267			13,207
Operating Income	2,551			4,629			4,282
Other Income and (Expense):
Allowance for equity funds used during construction	160			202			226
Earnings from equity method investments	106			59			—
Interest expense, net of amounts capitalized	(1,694		)	(1,317		)	(840		)
Other income (expense), net	(55		)	(93		)	(39		)
Total other income and (expense)	(1,483		)	(1,149		)	(653		)
Earnings Before Income Taxes	1,068			3,480			3,629
Income taxes	142			951			1,194
Consolidated Net Income	926			2,529			2,435
Less:
Dividends on preferred and preference stock of subsidiaries	38			45			54
Net income attributable to noncontrolling interests	46			36			14
Consolidated Net Income Attributable to Southern Company	$	842		$	2,448		$	2,367
Common Stock Data:
Earnings per share —
Basic	$	0.84		$	2.57		$	2.60
Diluted	0.84			2.55			2.59
Average number of shares of common stock outstanding — (in millions)
Basic	1,000			951			910
Diluted	1,008			958			914

The accompanying notes are ~~being amortized~~an integral part of these consolidated financial statements.

Table of Contents Index to Financial Statements

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2017, 2016, and ~~recovered over~~2015

Southern Company and Subsidiary Companies 2017 Annual Report



	2017			2016			2015
	(in millions)
Consolidated Net Income	$	926		$	2,529		$	2,435
Other comprehensive income:
Qualifying hedges:
Changes in fair value, net of tax of $34, $(84), and $(8), respectively	57			(136		)	(13		)
Reclassification adjustment for amounts included in net income, net of tax of $(37), $43, and $4, respectively	(60		)	69			6
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax of $6, $10, and $(1), respectively	17			13			(2		)
Reclassification adjustment for amounts included in net income, net of tax of $(6), $3, and $4, respectively	(23		)	4			7
Total other comprehensive income (loss)	(9		)	(50		)	(2		)
Less:
Dividends on preferred and preference stock of subsidiaries	38			45			54
Comprehensive income attributable to noncontrolling interests	46			36			14
Consolidated Comprehensive Income Attributable to Southern Company	$	833		$	2,398		$	2,365

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents Index to Financial Statements

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the ~~affected unit's remaining useful life, as established prior~~Years Ended December 31, 2017, 2016, and 2015

Southern Company and Subsidiary Companies 2017 Annual Report



	2017			2016			2015
				(in millions)
Operating Activities:
Consolidated net income	$	926		$	2,529		$	2,435
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	3,457			2,923			2,395
Deferred income taxes	166			(127		)	1,404
Collateral deposits	(4		)	(102		)	—
Allowance for equity funds used during construction	(160		)	(202		)	(226		)
Pension and postretirement funding	(2		)	(1,029		)	(7		)
Settlement of asset retirement obligations	(177		)	(171		)	(37		)
Stock based compensation expense	109			121			99
Hedge settlements	6			(233		)	(17		)
Estimated loss on Kemper IGCC	3,179			428			365
Income taxes receivable, non-current	(47		)	(122		)	(413		)
Other, net	(109		)	(99		)	49
Changes in certain current assets and liabilities —
-Receivables	(199		)	(544		)	243
-Fossil fuel for generation	36			178			61
-Natural gas for sale	36			(226		)	—
-Other current assets	(143		)	(206		)	(152		)
-Accounts payable	(280		)	301			(353		)
-Accrued taxes	(142		)	1,456			352
-Retail fuel cost over recovery	(212		)	(231		)	289
-Mirror CWIP	—			—			(271		)
-Other current liabilities	(45		)	250			58
Net cash provided from operating activities	6,395			4,894			6,274
Investing Activities:
Business acquisitions, net of cash acquired	(1,070		)	(10,689		)	(1,719		)
Property additions	(7,423		)	(7,310		)	(5,674		)
Proceeds pursuant to the Toshiba Guarantee, net of joint owner portion	1,682			—			—
Investment in restricted cash	(17		)	(733		)	(160		)
Distribution of restricted cash	34			742			154
Nuclear decommissioning trust fund purchases	(811		)	(1,160		)	(1,424		)
Nuclear decommissioning trust fund sales	805			1,154			1,418
Cost of removal, net of salvage	(313		)	(245		)	(167		)
Change in construction payables, net	259			(121		)	402
Investment in unconsolidated subsidiaries	(152		)	(1,444		)	—
Payments pursuant to LTSAs	(227		)	(134		)	(197		)
Other investing activities	42			(108		)	87
Net cash used for investing activities	(7,191		)	(20,048		)	(7,280		)
Financing Activities:
Increase (decrease) in notes payable, net	(401		)	1,228			73
Proceeds —
Long-term debt	5,858			16,368			7,029
Common stock	793			3,758			256
Preferred stock	250			—			—
Short-term borrowings	1,259			—			755
Redemptions and repurchases —
Long-term debt	(2,930		)	(3,145		)	(3,604		)
Common stock	—			—			(115		)
Interest-bearing refundable deposits	—			—			(275		)
Preferred and preference stock	(658		)	—			(412		)
Short-term borrowings	(659		)	(478		)	(255		)
Distributions to noncontrolling interests	(119		)	(72		)	(18		)
Capital contributions from noncontrolling interests	80			682			341
Payment of common stock dividends	(2,300		)	(2,104		)	(1,959		)
Other financing activities	(222		)	(512		)	(116		)
Net cash provided from financing activities	951			15,725			1,700
Net Change in Cash and Cash Equivalents	155			571			694
Cash and Cash Equivalents at Beginning of Year	1,975			1,404			710
Cash and Cash Equivalents at End of Year	$	2,130		$	1,975		$	1,404

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents Index to Financial Statements

CONSOLIDATED BALANCE SHEETS

At December 31, 2017 and 2016

Southern Company and Subsidiary Companies 2017 Annual Report



Assets	2017			2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	2,130		$	1,975
Receivables —
Customer accounts receivable	1,806			1,583
Energy marketing receivable	607			623
Unbilled revenues	810			706
Under recovered fuel clause revenues	171			—
Income taxes receivable, current	63			544
Other accounts and notes receivable	635			377
Accumulated provision for uncollectible accounts	(44		)	(43		)
Materials and supplies	1,438			1,462
Fossil fuel for generation	594			689
Natural gas for sale	595			631
Prepaid expenses	452			364
Other regulatory assets, current	604			581
Other current assets	211			230
Total current assets	10,072			9,722
Property, Plant, and Equipment:
In service	103,542			98,416
Less: Accumulated depreciation	31,457			29,852
Plant in service, net of depreciation	72,085			68,564
Nuclear fuel, at amortized cost	883			905
Construction work in progress	6,904			8,977
Total property, plant, and equipment	79,872			78,446
Other Property and Investments:
Goodwill	6,268			6,251
Equity investments in unconsolidated subsidiaries	1,513			1,549
Other intangible assets, net of amortization of $186 and $62 at December 31, 2017 and December 31, 2016, respectively	873			970
Nuclear decommissioning trusts, at fair value	1,832			1,606
Leveraged leases	775			774
Miscellaneous property and investments	249			270
Total other property and investments	11,510			11,420
Deferred Charges and Other Assets:
Deferred charges related to income taxes	825			1,629
Unamortized loss on reacquired debt	206			223
Other regulatory assets, deferred	6,943			6,851
Other deferred charges and assets	1,577			1,406
Total deferred charges and other assets	9,551			10,109
Total Assets	$	111,005		$	109,697

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents Index to Financial Statements

CONSOLIDATED BALANCE SHEETS

At December 31, 2017 and 2016

Southern Company and Subsidiary Companies 2017 Annual Report



Liabilities and Stockholders' Equity	2017		2016
	(in millions)
Current Liabilities:
Securities due within one year	$	3,892	$	2,587
Notes payable	2,439		2,241
Energy marketing trade payables	546		597
Accounts payable	2,530		2,228
Customer deposits	542		558
Accrued taxes —
Accrued income taxes	6		193
Unrecognized tax benefits	18		385
Other accrued taxes	613		667
Accrued interest	488		518
Accrued compensation	959		915
Asset retirement obligations, current	351		378
Acquisitions payable	5		489
Other regulatory liabilities, current	337		236
Other current liabilities	868		925
Total current liabilities	13,594		12,917
Long-Term Debt (See accompanying statements)	44,462		42,629
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	6,842		14,092
Deferred credits related to income taxes	7,256		219
Accumulated deferred ITCs	2,267		2,228
Employee benefit obligations	2,256		2,299
Asset retirement obligations, deferred	4,473		4,136
Accrued environmental remediation	389		397
Other cost of removal obligations	2,684		2,748
Other regulatory liabilities, deferred	239		258
Other deferred credits and liabilities	691		880
Total deferred credits and other liabilities	27,097		27,257
Total Liabilities	85,153		82,803
Redeemable Preferred Stock of Subsidiaries (See accompanying statements)	324		118
Redeemable Noncontrolling Interests (See accompanying statements)	—		164
Total Stockholders' Equity (See accompanying statements)	25,528		26,612
Total Liabilities and Stockholders' Equity	$	111,005	$	109,697
Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents Index to Financial Statements

CONSOLIDATED STATEMENTS OF CAPITALIZATION

At December 31, 2017 and 2016

Southern Company and Subsidiary Companies 2017 Annual Report



		2017			2016			2017		2016
		(in millions)						(percent of total)
Long-Term Debt:
Long-term debt payable to affiliated trusts —
Variable rate (4.44% at 12/31/17) due 2042		$	206		$	206
Long-term senior notes and debt —
Maturity	Interest Rates
2017	1.30% to 7.20%	—			2,019
2018	1.50% to 5.40%	2,402			2,403
2019	1.85% to 5.55%	3,074			3,076
2020	2.00% to 4.75%	2,273			1,326
2021	2.35% to 9.10%	2,643			2,655
2022	1.00% to 8.70%	2,016			1,378
2023 through 2047	1.85% to 7.30%	22,142			20,369
Variable rates (1.82% to 3.75% at 1/1/17) due 2017		—			461
Variable rates (2.29% to 3.05% at 12/31/17) due 2018		1,420			1,520
Variable rates (2.04% to 2.18% at 12/31/17) due 2020		825			—
Variable rates (2.55% to 2.79% at 12/31/17) due 2021		25			25
Variable rate (3.75% at 1/1/17) due 2032 to 2036		—			15
Total long-term senior notes and debt		36,820			35,247
Other long-term debt —
Pollution control revenue bonds —
Maturity	Interest Rates
2019	4.55%	25			25
2022	2.10% to 2.35%	90			90
2023 through 2049	1.15% to 5.15%	1,379			1,339
Variable rates (2.45% to 2.50% at 12/31/17) due 2018		40			76
Variable rates (1.86% to 1.87% at 12/31/17) due 2021		65			65
Variable rates (1.83% to 1.84% at 12/31/17) due 2022		17			17
Variable rates (1.59% to 1.88% at 12/31/17) due 2024 to 2053		1,680			1,721
Plant Daniel revenue bonds (7.13%) due 2021		270			270
FFB loans —
2.57% to 3.86% due 2020		44			44
2.57% to 3.86% due 2021		44			44
2.57% to 3.86% due 2022		44			44
2.57% to 3.86% due 2023 to 2044		2,493			2,493
First mortgage bonds —
4.70% due 2019		50			50
2.66% to 6.58% due 2023 to 2057		975			575
Gas facility revenue bonds —
Variable rate (1.71% at 12/31/17) due 2022		47			47
Variable rate (1.71% at 12/31/17) due 2024 to 2033		154			154
Junior subordinated notes (5.00% to 6.25%) due 2057 to 2077		3,570			2,350
Total other long-term debt		10,987			9,404
Unamortized fair value adjustment of long-term debt		525			578
Capitalized lease obligations		204			136
Unamortized debt premium		44			52
Unamortized debt discount		(206		)	(194		)
Unamortized debt issuance expense		(226		)	(213		)
Total long-term debt (annual interest requirement — $1.8 billion)		48,354			45,216
Less amount due within one year		3,892			2,587
Long-term debt excluding amount due within one year		44,462			42,629			63.2	%	61.3	%

Table of Contents Index to Financial Statements



CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 2017 and 2016 Southern Company and Subsidiary Companies 2017 Annual Report
	2017			2016			2017		2016
	(in millions)						(percent of total)
Redeemable Preferred Stock of Subsidiaries:
Cumulative preferred stock
$100 par or stated value — 4.20% to 5.44%
Authorized — 20 million shares
Outstanding — 1 million shares	324			81
$1 par value — 5.83%
Authorized — 28 million shares
Outstanding — 2017: no shares
— 2016: 2 million shares: $25 stated value	—			37
Total redeemable preferred stock of subsidiaries (annual dividend requirement — $16 million)	324			118			0.5		0.2
Redeemable Noncontrolling Interests	—			164			—		0.2
Common Stockholders' Equity:
Common stock, par value $5 per share —	5,038			4,952
Authorized — 1.5 billion shares
Issued — 2017: 1.0 billion shares
— 2016: 991 million shares
Treasury — 2017: 0.9 million shares
— 2016: 0.8 million shares
Paid-in capital	10,469			9,661
Treasury, at cost	(36		)	(31		)
Retained earnings	8,885			10,356
Accumulated other comprehensive loss	(189		)	(180		)
Total common stockholders' equity	24,167			24,758			34.4		35.6
Preferred and Preference Stock of Subsidiaries and Noncontrolling Interests:
Non-cumulative preferred stock
$25 par value — 6.00% to 6.13%
Authorized — 60 million shares
Outstanding — 2017: no shares
— 2016: 2 million shares	—			45
Non-cumulative preference stock
$1 par value — 6.45% to 6.50%
Authorized — 65 million shares
Outstanding — 2017: no shares	—			196
— 2016: 8 million shares
$100 par or stated value — 5.60% to 6.50%
Outstanding — 2017: no shares	—			368
— 2016: 4 million shares
Noncontrolling interests	1,361			1,245
Total preferred and preference stock of subsidiaries and noncontrolling interests	1,361			1,854			1.9		2.7
Total stockholders' equity	25,528			26,612
Total Capitalization	$	70,314		$	69,523		100.0	%	100.0	%

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents Index to Financial Statements

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

For the Years Ended December 31, 2017, 2016, and 2015

Southern Company and Subsidiary Companies 2017 Annual Report



	Southern Company Common Stockholders' Equity
	Number of Common Shares			Common Stock											Accumulated Other Comprehensive Income (Loss)			Preferred and Preference Stock of Subsidiaries			Noncontrolling Interests
	Issued	Treasury		Par Value		Paid-In Capital			Treasury			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Preferred and Preference Stock of Subsidiaries			Noncontrolling Interests			Total
	(in thousands)			(in millions)
Balance at December 31, 2014	908,502	(725	)	$	4,539	$	5,955		$	(26	)	$	9,609		$	(128	)	$	756		$	221		$	20,926
Consolidated net income attributable to Southern Company	—	—		—		—			—			2,367			—			—			—			2,367
Other comprehensive income (loss)	—	—		—		—			—			—			(2		)	—			—			(2		)
Stock issued	6,571	(2,599	)	33		223			—			—			—			—			—			256
Stock-based compensation	—	—		—		100			—			—			—			—			—			100
Stock repurchased, at cost	—	—		—		—			(115		)	—			—			—			—			(115		)
Cash dividends of $2.1525 per share	—	—		—		—			—			(1,959		)	—			—			—			(1,959		)
Preference stock redemption	—	—		—		—			—			—			—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—		—			—			—			—			—			567			567
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(18		)	(18		)
Net loss attributable to noncontrolling interests	—	—		—		—			—			—			—			—			12			12
Other	—	(28	)	—		4			(1		)	(7		)	—			3			(1		)	(2		)
Balance at December 31, 2015	915,073	(3,352	)	4,572		6,282			(142		)	10,010			(130		)	609			781			21,982
Consolidated net income attributable to Southern Company	—	—		—		—			—			2,448			—			—			—			2,448
Other comprehensive income (loss)	—	—		—		—			—			—			(50		)	—			—			(50		)
Stock issued	76,140	2,599		380		3,263			115			—			—			—			—			3,758
Stock-based compensation	—	—		—		120			—			—			—			—			—			120
Cash dividends of $2.2225 per share	—	—		—		—			—			(2,104		)	—			—			—			(2,104		)
Contributions from noncontrolling interests	—	—		—		—			—			—			—			—			618			618
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(57		)	(57		)
Purchase of membership interests from noncontrolling interests	—	—		—		—			—			—			—			—			(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—		—			—			—			—			—			32			32
Other	—	(66	)	—		(4		)	(4		)	2			—			—			—			(6		)
Balance at December 31, 2016	991,213	(819	)	4,952		9,661			(31		)	10,356			(180		)	609			1,245			26,612
Consolidated net income attributable to Southern Company	—	—		—		—			—			842			—			—			—			842
Other comprehensive income (loss)	—	—		—		—			—			—			(9		)	—			—			(9		)
Stock issued	17,319	—		86		707			—			—			—			—			—			793
Stock-based compensation	—	—		—		105			—			—			—			—			—			105
Cash dividends of $2.3000 per share	—	—		—		—			—			(2,300		)	—			—			—			(2,300		)
Preferred and preference stock redemptions	—	—		—		—			—			—			—			(609		)	—			(609		)
Contributions from noncontrolling interests	—	—		—		—			—			—			—			—			79			79
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(122		)	(122		)
Net income attributable to noncontrolling interests	—	—		—		—			—			—			—			—			44			44
Reclassification from redeemable noncontrolling interests	—	—		—		—			—			—			—			—			114			114
Other	—	(110	)	—		(4		)	(5		)	(13		)	—			—			1			(21		)
Balance at December 31, 2017	1,008,532	(929	)	$	5,038	$	10,469		$	(36	)	$	8,885		$	(189	)	$	—		$	1,361		$	25,528

The accompanying notes are an integral part of these consolidated financial statements.

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NOTES TO FINANCIAL STATEMENTS

Southern Company and Subsidiary Companies 2017 Annual Report

Index to the ~~decision regarding early retirement through Rate CNP Compliance.~~Notes to Financial Statements

~~II-86~~

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NOTES (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

~~In April 2015, as part~~1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

The Southern Company (Southern Company or the Company) is the parent company of four traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four 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 the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants and is managing construction of Plant Vogtle Units 3 and 4. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. See Note 12 under "Southern Company Gas – Proposed Sale of Elizabethtown Gas and Elkton Gas" for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its ~~environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7 (200 MWs). Additionally,~~natural gas distribution utilities.

The financial statements reflect Southern Company's investments in ~~April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available~~the subsidiaries on a ~~limited basis with~~consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation.

The traditional electric operating companies, Southern Power, certain subsidiaries of Southern Company Gas, and certain other subsidiaries are subject to regulation by the FERC, and the traditional electric operating companies and natural gas asdistribution utilities are also subject to regulation by their respective state PSCs or other applicable state regulatory agencies. As such, the ~~fuel source. In~~consolidated financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the ~~joint stipulation entered~~accounting policies and practices prescribed by relevant state PSCs or other applicable state regulatory agencies. The preparation of financial statements in ~~connection~~conformity with ~~a civil enforcement action by~~GAAP requires the ~~EPA, Alabama Power retired Plant Barry Unit 3 (225 MWs)~~use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in ~~August 2015 and it is no longer available for generation. Alabama Power expects~~the financial statements have been reclassified to ~~cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas by April 2016.~~

In accordance with this accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized and recovered through Rate CNP Compliance over the remaining useful lives, as established priorconform to the ~~decision for retirement. As a result, these decisions will not have a significant~~current year presentation. These reclassifications had no impact on Southern Company's results of operations, financial ~~statements.~~

~~Nuclear Waste Fund Accounting Order~~position, or cash flows.

In 2015, Georgia Power identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the ~~U.S. District Court for~~second quarter 2015, Georgia Power recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million. Georgia Power evaluated the ~~District~~effects of ~~Columbia ordered~~this error on the ~~DOE~~interim and annual periods that included the billing error. Based on an analysis of qualitative and quantitative factors, Georgia Power determined the error was not material to ~~cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the DOE either complies with the Nuclear Waste Policy Act~~any affected period and, therefore, an amendment of ~~1982 or until the U.S. Congress enacts an alternative waste management plan. The DOE formally set the fee to zero effective May 16, 2014.~~previously filed financial statements was not required.

Recently Issued Accounting Standards

Revenue

In ~~August~~ 2014, the ~~Alabama PSC~~FASB issued ~~an order to provide~~ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for ~~the continued recovery~~revenue recognition with a five-step model for recognizing and measuring revenue from ~~customers of amounts associated~~contracts with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, Alabama Power was authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). On December 1, 2015, the Alabama PSC issued an order for Alabama Power to discontinue recording the amounts recovered from customers in a regulatory liability account and transfer amounts recorded in the regulatory liability to Rate ECR. On December 1, 2015, Alabama Power transferred $20 million from the regulatory liability to Rate ECR to offset fuel expense.

~~Cost of Removal Accounting Order~~

In accordance with an accounting order issued in November 2014 by the Alabama PSC, in December 2014, Alabama Power fully amortized the balance of $123 million in certain regulatory asset accounts and offset this amortization expense with the amortization of $120 millioncustomers. The underlying principle of the ~~regulatory liability for other cost~~new standard is to recognize revenue to depict the transfer of ~~removal obligations.~~goods or services to customers at the amount expected to be collected. The ~~regulatory asset accounts fully amortized~~new standard also requires enhanced disclosures regarding the nature, amount, timing, and ~~terminated as~~uncertainty of ~~December 31, 2014 represented costs previously deferred under~~revenue and the related cash flows arising from contracts with customers.

Most of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a ~~compliance and pension cost accounting order~~defined contractual term, as well as ~~a non-nuclear outage accounting order, which were approved by~~longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements.

Southern Company has completed the ~~Alabama PSC in 2012~~evaluation of all revenue streams and ~~2013, respectively. Approximately $95 million~~determined that the adoption of ~~non-nuclear outage costs~~ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and ~~$28 million~~alternative revenue programs, are excluded from the scope of ~~compliance~~ASC 606 and, ~~pension costs were fully amortized in December 2014.~~

~~Georgia Power~~

~~Rate Plans~~

In 2013, the Georgia PSC voted to approve the 2013 ARP. The 2013 ARP reflects the settlement agreement among Georgia Power, the Georgia PSC's Public Interest Advocacy Staff, and 11 of the 13 intervenors.

In January 2014, in accordance with the 2013 ARP, Georgia Power increased its tariffs as follows: (1) traditional base tariff rates by approximately $80 million; (2) Environmental Compliance Cost Recovery (ECCR) tariff by approximately $25 million; (3) Demand-Side Management (DSM) tariffs by approximately $1 million; and (4) Municipal Franchise Fee (MFF) tariff by approximately $4 million, for a total increase in base revenues of approximately $110 million.

On February 19, 2015, in accordance with the 2013 ARP, the Georgia PSC approved an increase to tariffs effective January 1, 2015 as follows: (1) traditional base tariff rates by approximately $107 million; (2) ECCR tariff by approximately $23 million; (3) DSM tariffs by approximately $3 million; and (4) MFF tariff by approximately $3 million, for a total increase in base revenues of approximately $136 million.

On December 16, 2015, in accordance with the 2013 ARP, the Georgia PSC approved an increase to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately $49 million; (2) ECCR tariff by approximately $75 million; (3) DSM tariffs by approximately $3 million; and (4) MFF tariff by approximately $13 million, for a total increase in base revenues of approximately $140 million.

~~Under the 2013 ARP, Georgia Power's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00%~~therefore, will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2014, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power will refund to retail customers approximately $11 million in 2016, as

~~II-87~~

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NOTES (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. Southern Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.

The new standard is effective for reporting periods beginning after December 15, 2017. Southern Company applied the modified retrospective method of adoption effective January 1, 2018. Southern Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.

Leases

Other

In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, Southern Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. Southern Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. Southern Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of Southern Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. Southern Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

December 15, 2019, with early adoption permitted. Southern Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements.

On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. Southern Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.

Regulatory Assets and Liabilities

The traditional electric operating companies and natural gas distribution utilities are subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:



	2017			2016			Note
	(in millions)
Retiree benefit plans	$	3,931		$	3,959		(a,n)
Asset retirement obligations-asset	1,133			1,080			(b,n)
Deferred income tax charges	814			1,590			(b,p)
Environmental remediation-asset	511			491			(j,n)
Property damage reserves-asset	333			206			(i)
Under recovered regulatory clause revenues	317			273			(g)
Remaining net book value of retired assets	306			351			(o)
Loss on reacquired debt	223			243			(c)
Vacation pay	183			182			(f,n)
Long-term debt fair value adjustment	138			155			(d)
Deferred PPA charges	119			141			(e,n)
Kemper County energy facility	88			201			(h)
Other regulatory assets	511			487			(k)
Deferred income tax credits	(7,261		)	(219		)	(b,p)
Other cost of removal obligations	(2,684		)	(2,774		)	(b)
Over recovered regulatory clause revenues	(155		)	(203		)	(g)
Property damage reserves-liability	(135		)	(177		)	(l)
Other regulatory liabilities	(266		)	(120		)	(m)
Total regulatory assets (liabilities), net	$	(1,894	)	$	5,866

Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:


(a)	Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.


(b)	Asset retirement and other cost of removal obligations are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 80 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.


(c)	Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years.


(d)	Recovered over the remaining life of the original debt issuances, which range up to 21 years. For additional information see Note 12 under "Southern Company – Merger with Southern Company Gas."


(e)	Recovered over the life of the PPA for periods up to six years.


(f)	Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.


(g)	Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs or other applicable regulatory agencies over periods generally not exceeding 10 years.


(h)	Includes $114 million of regulatory assets and $26 million of regulatory liabilities to be recovered over periods of eight and six years, respectively. For additional information, see Note 3 under "Kemper County Energy Facility – Rate Recovery – Kemper Settlement Agreement."

(i)

Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $319 million related to the under-recovery from January 2014 through December 2017 is expected to be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information.


(j)	Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed.


(k)	Comprised of numerous immaterial components including nuclear outage, fuel-hedging losses, deferred income tax charges - Medicare subsidy, cancelled construction projects, building and generating plant leases, property tax, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSCs over periods generally not exceeding 50 years.


(l)	Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs.


(m)	Comprised of numerous immaterial components including retiree benefit plans, fuel-hedging gains, AROs, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs or other applicable regulatory agencies generally over periods not exceeding 20 years.


(n)	Not earning a return as offset in rate base by a corresponding asset or liability.


(o)	Amortized as approved by the appropriate state PSCs over periods generally up to 48 years.


(p)	As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization. The recovery and amortization of these amounts will be determined by the appropriate state PSCs or other applicable regulatory agencies. See Note 3 under "Regulatory Matters" and Note 5 for additional information.

In the event that a portion of a traditional electric operating company's or a natural gas distribution utility's operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional electric operating company or natural gas distribution utility would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

are to be reflected in rates. See Note 3 under "Regulatory Matters – Alabama Power," " – Georgia Power," " – Gulf Power," and " – Southern Company Gas" and "Kemper County Energy Facility" for additional information.

Revenues

Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Retail rates for the traditional electric operating companies and natural gas distribution utilities may include provisions to adjust billings for fluctuations in fuel and purchased gas costs, fuel hedging, the energy component of purchased power costs, and certain other costs. For the traditional electric operating companies, revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors.

The tariffs for several of the natural gas distribution utilities include provisions which allow for the recognition of certain revenues prior to the time such revenues are billed to customers, so long as the amounts recognized will be collected from customers within 24 months. Programs of this type include weather normalization adjustments, revenue normalization mechanisms, and revenue true-up adjustments and are referred to as alternative revenue programs.

Southern Company's electric utility subsidiaries and Southern Company Gas have a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel.

Cost of Natural Gas

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, Southern Company Gas charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Southern Company Gas defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively.

Income and Other Taxes

Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies and Southern Company Gas are amortized over the average lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Under current tax law, certain projects at Southern Power are eligible for federal ITCs or cash grants. Southern Power has elected to receive ITCs. The credits are recorded as a deferred credit and are amortized to income tax expense over the life of the asset. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. In addition, certain projects are eligible for federal PTCs, which are recorded to income tax expense based on KWH production.

Federal ITCs and PTCs, as well as state ITCs and other state tax credits available to reduce income taxes payable, were not fully utilized in 2017 and will be carried forward and utilized in future years. In addition, Southern Company is expected to have a consolidated federal net operating loss (NOL) carryforward for the 2017 tax year along with various state NOL carryforwards, which would result in income tax benefits in the future, if utilized. See Note 5 under "Current and Deferred Income Taxes – Tax Credit Carryforwards" and " – Net Operating Loss" for additional information.

Southern Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.

Table of Contents Index to Financial Statements

NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.

The Southern Company system's property, plant, and equipment in service consisted of the following at December 31:



	2017		2016
	(in millions)
Electric utilities:
Generation	$	51,279	$	48,836
Transmission	11,562		11,156
Distribution	19,239		18,418
General	4,276		4,629
Plant acquisition adjustment	126		126
Electric utility plant in service	86,482		83,165
Natural gas distribution utilities:
Transportation and distribution	13,078		11,996
Utility plant in service	99,560		95,161
Information technology equipment and software	752		544
Communications equipment	456		424
Storage facilities	1,598		1,463
Other	1,176		824
Total other plant in service	3,982		3,255
Total plant in service	$	103,542	$	98,416

The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs. In accordance with their respective state PSC orders, Alabama Power and Georgia Power defer and amortize nuclear refueling costs over the unit's operating cycle, which ranges from 18 to 24 months.

Assets acquired under a capital lease are included in property, plant, and equipment and are further detailed in the table below:



	Asset Balances at December 31,
	2017			2016
	(in millions)
Office buildings	$	216		$	61
Nitrogen plant^(*)	—			83
Computer-related equipment	51			63
Gas pipeline	6			6
Less: Accumulated amortization	(72		)	(69		)
Balance, net of amortization	$	201		$	144


(*)	Represents a nitrogen supply agreement for the air separation unit of the Kemper County energy facility, which was terminated following the suspension of the gasifier portion of the project. See Note 6 under "Capital Leases" for additional information.

The amount of non-cash property additions recognized for the years ended December 31, 2017, 2016, and 2015 was $985 million, $1.3 billion, and $844 million, respectively. These amounts are comprised of construction-related accounts payable outstanding at each year end. Also, the amount of non-cash property additions associated with capitalized leases for the years ended December 31, 2017, 2016, and 2015 was $162 million, $18 million, and $13 million, respectively.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Depreciation and Amortization

Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9% in 2017 and 3.0% in each of 2016 and 2015. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and/or other applicable state and federal regulatory agencies for the traditional electric operating companies and natural gas distribution utilities. Accumulated depreciation for utility plant in service totaled $30.8 billion and $29.3 billion at December 31, 2017 and 2016, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Certain of Southern Power's generation assets related to natural gas-fired facilities are depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of, and revenues from, these assets.

Under the terms of the 2013 ARP, Georgia Power amortized approximately $14 million annually from 2014 through 2016 of its remaining regulatory liability related to other cost of removal obligations.

See Note 3 under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for information regarding depreciation and amortization adjustments related to the other cost of removal regulatory liability.

Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from two to 65 years. Accumulated depreciation for other plant in service totaled $673 million and $550 million at December 31, 2017 and 2016, respectively.

Asset Retirement Obligations and Other Costs of Removal

AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. Each traditional electric operating company and natural gas distribution utility has received accounting guidance from its state PSC or applicable state regulatory agency allowing the continued accrual or recovery of other retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability and amounts to be recovered are reflected in the balance sheet as a regulatory asset.

The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule), principally ash ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded as the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates.

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Southern Company and Subsidiary Companies 2017 Annual Report

Details of the AROs included in the balance sheets are as follows:



	2017			2016
	(in millions)
Balance at beginning of year	$	4,514		$	3,759
Liabilities incurred	16			66
Liabilities settled	(177		)	(171		)
Accretion	179			162
Cash flow revisions	292			698
Balance at end of year	$	4,824		$	4,514

In 2017 and 2016, the increases in cash flow revisions are primarily related to changes in closure strategy for ash ponds, landfills, and gypsum cells and the increases in liabilities settled are primarily related to ash pond closure activity.

The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the traditional electric operating companies will continue to periodically update these cost estimates as necessary.

Nuclear Decommissioning

The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the IRS. While Alabama Power and Georgia Power are allowed to prescribe an overall investment policy to the Funds' managers, neither Southern Company nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of Southern Company, Alabama Power, and Georgia Power. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.

Southern Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis.

The Funds at Georgia Power participate in a securities lending program through the managers of the Funds. Under this program, the Funds' investment securities are loaned to institutional investors for a fee. Securities loaned are fully collateralized by cash, letters of credit, and/or securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. As of December 31, 2017 and 2016, approximately $76 million and $56 million, respectively, of the fair market value of the Funds' securities were on loan and pledged to creditors under the Funds' managers' securities lending program. The fair value of the collateral received was approximately $77 million and $58 million at December 31, 2017 and 2016, respectively, and can only be sold by the borrower upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows.

At December 31, 2017, investment securities in the Funds totaled $1.8 billion, consisting of equity securities of $1.1 billion, debt securities of $725 million, and $47 million of other securities. At December 31, 2016, investment securities in the Funds totaled $1.6 billion, consisting of equity securities of $878 million, debt securities of $685 million, and $41 million of other securities. These amounts include the investment securities pledged to creditors and collateral received and exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases and the securities lending program.

Sales of the securities held in the Funds resulted in cash proceeds of $0.8 billion, $1.2 billion, and $1.4 billion in 2017, 2016, and 2015, respectively, all of which were reinvested. For 2017, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $233 million, which included $181 million related to unrealized gains on securities held in the Funds at December 31, 2017. For 2016, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $114 million, which included $48 million related to unrealized losses on securities held in the Funds at

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Southern Company and Subsidiary Companies 2017 Annual Report

December 31, 2016. For 2015, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $11 million, which included $83 million related to unrealized gains and losses on securities held in the Funds at December 31, 2015. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired.

For Alabama Power, approximately $18 million and $19 million at December 31, 2017 and 2016, respectively, previously recorded in internal reserves is being transferred into the Funds through 2040 as approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.

At December 31, 2017 and 2016, the accumulated provisions for the external decommissioning trust funds were as follows:



	External Trust Funds
	2017		2016
	(in millions)
Plant Farley	$	902	$	790
Plant Hatch	583		511
Plant Vogtle Units 1 and 2	346		303

Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. The estimated costs of decommissioning as of December 31, 2017 based on the most current studies, which were performed in 2013 for Alabama Power's Plant Farley and in 2015 for the Georgia Power plants, were as follows for Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2:



	Plant Farley		Plant Hatch		Plant Vogtle Units 1 and 2
Decommissioning periods:
Beginning year	2037		2034		2047
Completion year	2076		2075		2079
	(in millions)
Site study costs:
Radiated structures	$	1,362	$	678	$	568
Spent fuel management	—		160		147
Non-radiated structures	80		64		89
Total site study costs	$	1,442	$	902	$	804

For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study, and Georgia Power's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved Georgia Power's annual decommissioning cost for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Georgia Power expects the Georgia PSC to review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs in Georgia Power's 2019 base rate case. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.4% for Alabama Power and Georgia Power, respectively.

Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.

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Southern Company and Subsidiary Companies 2017 Annual Report

Allowance for Funds Used During Construction and Interest Capitalized

The traditional electric operating companies and certain of the natural gas distribution utilities record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional electric operating companies' and natural gas distribution utilities' regulated rates is capitalized in accordance with standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes, as a percentage of net income, was 25.5%, 11.4%, and 12.8% for 2017, 2016, and 2015, respectively.

Cash payments for interest totaled $1.7 billion, $1.1 billion, and $809 million in 2017, 2016, and 2015, respectively, net of amounts capitalized of $89 million, $125 million, and $124 million, respectively.

Impairment of Long-Lived Assets

Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See "Leveraged Leases" herein and Note 3 under "Other Matters" and "Kemper County Energy Facility – Schedule and Cost Estimate" for additional information.

Goodwill and Other Intangible Assets and Liabilities

Southern Company's goodwill and other intangible assets and liabilities primarily relate to Southern Company's 2016 acquisitions of PowerSecure and Southern Company Gas. See Note 12 under "Southern Company – Acquisition of PowerSecure" and " – Merger with Southern Company Gas" for additional information. Also see Note 12 under "Southern Power" for additional information regarding other intangible assets related to Southern Power's PPA fair value adjustments.

At December 31, 2017 and 2016, goodwill was $6.3 billion. 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. Southern Company evaluated its goodwill in the fourth quarter 2017 and determined that no impairment was required.

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Southern Company and Subsidiary Companies 2017 Annual Report

At December 31, 2017 and 2016, other intangible assets were as follows:



		At December 31, 2017							At December 31, 2016
	Estimated Useful Life	Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net
		(in millions)							(in millions)
Other intangible assets subject to amortization:
Customer relationships	11-26 years	$	288	$	(83	)	$	205	$	268	$	(32	)	$	236
Trade names	5-28 years	159		(17		)	142		158		(5		)	153
Storage and transportation contracts	1-5 years	64		(34		)	30		64		(2		)	62
PPA fair value adjustments	10-20 years	456		(47		)	409		456		(22		)	434
Other	1-12 years	17		(5		)	12		11		(1		)	10
Total other intangible assets subject to amortization		$	984	$	(186	)	$	798	$	957	$	(62	)	$	895
Other intangible assets not subject to amortization:
Federal Communications Commission licenses		75		—			75		75		—			75
Total other intangible assets		$	1,059	$	(186	)	$	873	$	1,032	$	(62	)	$	970

Amortization associated with other intangible assets in 2017, 2016, and 2015 totaled $124 million, $50 million, and $3 million, respectively.

As of December 31, 2017, the estimated amortization associated with other intangible assets for the next five years is as follows:



	Amortization
	(in millions)
2018	$	95
2019	77
2020	65
2021	56
2022	51

Included in other deferred credits and liabilities on the balance sheet is $91 million of intangible liabilities that were recorded during acquisition accounting for transportation contracts at Southern Company Gas. At December 31, 2017, the accumulated amortization of these intangible liabilities was $50 million. The remaining estimated amortization associated with the intangible liabilities that will be recorded in natural gas revenues is as follows:



	Amortization
	(in millions)
2018	$	24
2019	17

Storm Damage Reserves

Each traditional electric operating company maintains a reserve to cover or is allowed to defer and recover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional electric operating companies accrued $41 million in 2017 and $40 million in each of 2016 and 2015. Alabama Power, Gulf Power, and Mississippi Power also have authority based on orders from their state PSCs to accrue certain additional amounts as circumstances warrant. In 2017, 2016, and 2015, there were no such additional accruals. See Note 3 under "Regulatory Matters – Alabama Power – Rate NDR" and

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Southern Company and Subsidiary Companies 2017 Annual Report

"Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information regarding Alabama Power's NDR and Georgia Power's deferred storm costs, respectively.

Leveraged Leases

Southern Company's net investment in domestic and international leveraged leases consists of the following at December 31:



	2017			2016
	(in millions)
Net rentals receivable	$	1,498		$	1,481
Unearned income	(723		)	(707		)
Investment in leveraged leases	775			774
Deferred taxes from leveraged leases	(252		)	(309		)
Net investment in leveraged leases	$	523		$	465

A summary of the components of income from the leveraged leases follows:



	2017			2016			2015
	(in millions)
Pretax leveraged lease income	$	25		$	25		$	20
Net impact of Tax Reform Legislation	48			—			—
Income tax expense	(9		)	(9		)	(7		)
Net leveraged lease income	$	64		$	16		$	13

Cash and Cash Equivalents

For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.

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Southern Company and Subsidiary Companies 2017 Annual Report

Materials and Supplies

Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.

Fuel Inventory

Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances of the electric utilities. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the traditional electric operating companies through fuel cost recovery rates approved by each state PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.

Natural Gas for Sale

The natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a weighted average cost of gas (WACOG) basis.

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. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's net income.

Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined 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.

Financial Instruments

Southern Company and its subsidiaries use derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Southern Company system's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statements of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives.

The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2017, the amount included in accounts payable in the balance sheets that the Company has recognized for the obligation to return cash collateral arising from derivative instruments was immaterial.

Southern Company is exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, certain changes in pension and other postretirement benefit plans, reclassifications for amounts included in net income, and dividends on preferred and preference stock of subsidiaries.

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Southern Company and Subsidiary Companies 2017 Annual Report

Accumulated OCI (loss) balances, net of tax effects, were as follows:



	Qualifying Hedges			Pension and Other Postretirement Benefit Plans			Accumulated Other Comprehensive Income (Loss)
	(in millions)
Balance at December 31, 2016	$	(115	)	$	(65	)	$	(180	)
Current period change	(4		)	(5		)	(9		)
Balance at December 31, 2017	$	(119	)	$	(70	)	$	(189	)

2. RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at Southern Company Gas and PowerSecure. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2018. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2018, no other postretirement trust contributions are expected.

In addition, Southern Company Gas has a qualified defined benefit, trusteed, pension plan covering certain eligible employees, which was closed in 2012 to new employees and reopened to all non-union employees on January 1, 2018. This qualified pension plan is funded in accordance with requirements of ERISA. No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the Southern Company Gas qualified pension plan are anticipated for the year ending December 31, 2018. Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses. For the year ending December 31, 2018, no other postretirement trust contributions are expected.

Actuarial Assumptions

The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below.



Assumptions used to determine net periodic costs:	2017		2016		2015
Pension plans
Discount rate – benefit obligations	4.40	%	4.58	%	4.17	%
Discount rate – interest costs	3.77		3.88		4.17
Discount rate – service costs	4.81		4.98		4.48
Expected long-term return on plan assets	7.92		8.16		8.20
Annual salary increase	4.37		4.37		3.59
Other postretirement benefit plans
Discount rate – benefit obligations	4.23	%	4.38	%	4.04	%
Discount rate – interest costs	3.54		3.66		4.04
Discount rate – service costs	4.64		4.85		4.39
Expected long-term return on plan assets	6.84		6.66		6.97
Annual salary increase	4.37		4.37		3.59

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Southern Company and Subsidiary Companies 2017 Annual Report



Assumptions used to determine benefit obligations:	2017		2016
Pension plans
Discount rate	3.80	%	4.40	%
Annual salary increase	4.32		4.37
Other postretirement benefit plans
Discount rate	3.68	%	4.23	%
Annual salary increase	4.32		4.37

The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of eight different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio.

An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows:



	Initial Cost Trend Rate		Ultimate Cost Trend Rate		Year That Ultimate Rate is Reached
Pre-65	6.50	%	4.50	%	2026
Post-65 medical	5.00		4.50		2026
Post-65 prescription	10.00		4.50		2026

An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2017 as follows:



	1 Percent Increase		1 Percent Decrease
	(in millions)
Benefit obligation	$	132	$	113
Service and interest costs	4		3

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Southern Company and Subsidiary Companies 2017 Annual Report

Pension Plans

The total accumulated benefit obligation for the pension plans was $12.6 billion at December 31, 2017 and $11.3 billion at December 31, 2016. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows:



	2017			2016
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	12,385		$	10,542
Acquisitions	—			1,244
Service cost	293			262
Interest cost	455			422
Benefits paid	(596		)	(466		)
Plan amendments	(26		)	39
Actuarial (gain) loss	1,297			342
Balance at end of year	13,808			12,385
Change in plan assets
Fair value of plan assets at beginning of year	11,583			9,234
Acquisitions	—			837
Actual return (loss) on plan assets	1,953			902
Employer contributions	52			1,076
Benefits paid	(596		)	(466		)
Fair value of plan assets at end of year	12,992			11,583
Accrued liability	$	(816	)	$	(802	)

At December 31, 2017, the projected benefit obligations for the qualified and non-qualified pension plans were $13.2 billion and $652 million, respectively. All pension plan assets are related to the qualified pension plans.

Amounts presented in the following tables exclude regulatory assets of $334 million associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company on July 1, 2016.

Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following:



	2017			2016
	(in millions)
Other regulatory assets, deferred	$	3,273		$	3,207
Other current liabilities	(53		)	(53		)
Employee benefit obligations	(763		)	(749		)
Other regulatory liabilities, deferred	(118		)	(87		)
Accumulated OCI	107			100

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Southern Company and Subsidiary Companies 2017 Annual Report

Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2017 and 2016 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2018.



	Prior Service Cost		Net (Gain) Loss
	(in millions)
Balance at December 31, 2017:
Accumulated OCI	$	3	$	104
Regulatory assets	14		3,140
Total	$	17	$	3,244
Balance at December 31, 2016:
Accumulated OCI	$	4	$	96
Regulatory assets	51		3,069
Total	$	55	$	3,165
Estimated amortization in net periodic pension cost in 2018:
Accumulated OCI	$	1	$	9
Regulatory assets	4		204
Total	$	5	$	213

The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2017 and 2016 are presented in the following table:



	Accumulated OCI			Regulatory Assets
	(in millions)
Balance at December 31, 2015	$	125		$	2,998
Net (gain) loss	(20		)	243
Change in prior service costs	2			37
Reclassification adjustments:
Amortization of prior service costs	(1		)	(13		)
Amortization of net gain (loss)	(6		)	(145		)
Total reclassification adjustments	(7		)	(158		)
Total change	(25		)	122
Balance at December 31, 2016	$	100		$	3,120
Net (gain) loss	15			227
Change in prior service costs	—			(26		)
Reclassification adjustments:
Amortization of prior service costs	(1		)	(11		)
Amortization of net gain (loss)	(7		)	(155		)
Total reclassification adjustments	(8		)	(166		)
Total change	7			35
Balance at December 31, 2017	$	107		$	3,155

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Southern Company and Subsidiary Companies 2017 Annual Report

Components of net periodic pension cost were as follows:



	2017			2016			2015
	(in millions)
Service cost	$	293		$	262		$	257
Interest cost	455			422			445
Expected return on plan assets	(897		)	(782		)	(724		)
Recognized net (gain) loss	162			150			215
Net amortization	12			14			25
Net periodic pension cost	$	25		$	66		$	218

Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.

Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2017, estimated benefit payments were as follows:



	Benefit Payments
	(in millions)
2018	$	634
2019	637
2020	663
2021	681
2022	704
2023 to 2027	3,836

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Other Postretirement Benefits

Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows:



	2017			2016
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	2,297		$	1,989
Acquisitions	—			338
Service cost	24			22
Interest cost	79			76
Benefits paid	(136		)	(119		)
Actuarial (gain) loss	65			(16		)
Plan amendments	3			—
Retiree drug subsidy	7			7
Balance at end of year	2,339			2,297
Change in plan assets
Fair value of plan assets at beginning of year	944			833
Acquisitions	—			100
Actual return (loss) on plan assets	154			58
Employer contributions	84			65
Benefits paid	(129		)	(112		)
Fair value of plan assets at end of year	1,053			944
Accrued liability	$	(1,286	)	$	(1,353	)

Amounts presented in the following tables exclude regulatory assets of $77 million associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company on July 1, 2016.

Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following:



	2017			2016
	(in millions)
Other regulatory assets, deferred	$	382		$	419
Other current liabilities	(5		)	(4		)
Employee benefit obligations	(1,281		)	(1,349		)
Other regulatory liabilities, deferred	(41		)	(41		)
Accumulated OCI	4			7

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Presented below are the amounts included in accumulated OCI and net regulatory assets (liabilities) at December 31, 2017 and 2016 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2018.



	Prior Service Cost		Net (Gain) Loss
	(in millions)
Balance at December 31, 2017:
Accumulated OCI	$	—	$	4
Net regulatory assets	21		320
Total	$	21	$	324
Balance at December 31, 2016:
Accumulated OCI	$	—	$	7
Net regulatory assets	25		353
Total	$	25	$	360
Estimated amortization as net periodic postretirement benefit cost in 2018:
Net regulatory assets	$	7	$	14

The components of OCI, along with the changes in the balance of net regulatory assets (liabilities), related to the other postretirement benefit plans for the plan years ended December 31, 2017 and 2016 are presented in the following table:



	Accumulated OCI			Net Regulatory Assets (Liabilities)
	(in millions)
Balance at December 31, 2015	$	8		$	411
Net (gain) loss	(1		)	(13		)
Reclassification adjustments:
Amortization of prior service costs	—			(6		)
Amortization of net gain (loss)	—			(14		)
Total reclassification adjustments	—			(20		)
Total change	(1		)	(33		)
Balance at December 31, 2016	$	7		$	378
Net (gain) loss	(3		)	(21		)
Change in prior service costs	—			3
Reclassification adjustments:
Amortization of prior service costs	—			(6		)
Amortization of net gain (loss)	—			(13		)
Total reclassification adjustments	—			(19		)
Total change	(3		)	(37		)
Balance at December 31, 2017	$	4		$	341

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Components of the other postretirement benefit plans' net periodic cost were as follows:



	2017			2016			2015
	(in millions)
Service cost	$	24		$	22		$	23
Interest cost	79			76			78
Expected return on plan assets	(66		)	(60		)	(58		)
Net amortization	20			21			21
Net periodic postretirement benefit cost	$	57		$	59		$	64

Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows:



	Benefit Payments		Subsidy Receipts			Total
	(in millions)
2018	$	144	$	(7	)	$	137
2019	148		(8		)	140
2020	151		(8		)	143
2021	154		(9		)	145
2022	156		(9		)	147
2023 to 2027	780		(48		)	732

Benefit Plan Assets

Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company's investment policies for both the pension plans and the other postretirement benefit plans cover a diversified mix of assets as described below. Derivative instruments may be used to gain efficient exposure to the various asset classes and as hedging tools. Additionally, the Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.

The investment strategy for plan assets related to the Company's qualified pension plans is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plans is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Southern Company plan employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Investment Strategies and Benefit Plan Asset Fair Values

A description of the major asset classes that the pension and other postretirement benefit plans are comprised of, along with the valuation methods used for fair value measurement, is provided below:



Description	Valuation Methodology
● Domestic equity: A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. ● International equity: A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.	Domestic and International equities such as common stocks, American depositary receipts, and real estate investment trusts that trade on public exchanges are classified as Level 1 investments and are valued at the closing price in the active market. Equity funds with unpublished prices are valued as Level 2 when the underlying holdings are comprised of Level 1 or Level 2 equity securities.
● Fixed income: A mix of domestic and international bonds.	Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
● Trust-owned life insurance (TOLI): Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio.	Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate accounts. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.
● Special situations: Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as investments in promising new strategies of a longer-term nature. ● Real estate: Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. ● Private equity: Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.	Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.

The fair values, and actual allocations relative to the target allocations, of Southern Company's pension plan (excluding Southern Company Gas) as of December 31, 2017 and 2016 are presented below. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

These fair values exclude cash, receivables related to investment income and pending investment sales, and payables related to pending investment purchases.



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient				Target Allocation		Actual Allocation
As of December 31, 2017:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Domestic equity^(*)	$	2,405	$	1,159	$	—	$	—	$	3,564	26	%	31	%
International equity^(*)	1,555		1,403		—		—		2,958		25		25
Fixed income:											23		24
U.S. Treasury, government, and agency bonds	—		841		—		—		841
Mortgage- and asset-backed securities	—		8		—		—		8
Corporate bonds	—		1,201		—		—		1,201
Pooled funds	—		650		—		—		650
Cash equivalents and other	217		11		—		—		228
Real estate investments	469		—		—		1,188		1,657		14		13
Special situations	—		—		—		180		180		3		1
Private equity	—		—		—		669		669		9		6
Total	$	4,646	$	5,273	$	—	$	2,037	$	11,956	100	%	100	%


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient				Target Allocation		Actual Allocation
As of December 31, 2016:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Domestic equity^(*)	$	2,010	$	927	$	—	$	—	$	2,937	26	%	29	%
International equity^(*)	1,231		1,110		—		—		2,341		25		22
Fixed income:											23		29
U.S. Treasury, government, and agency bonds	—		588		—		—		588
Mortgage- and asset-backed securities	—		13		—		—		13
Corporate bonds	—		991		—		—		991
Pooled funds	—		524		—		—		524
Cash equivalents and other	996		2		—		—		998
Real estate investments	310		—		—		1,152		1,462		14		13
Special situations	—		—				180		180		3		2
Private equity	—		—		—		549		549		9		5
Total	$	4,547	$	4,155	$	—	$	1,881	$	10,583	100	%	100	%


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

The fair values of Southern Company Gas' pension plan assets for the period ended December 31, 2017 and 2016 are presented below. The fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Special situations (absolute return and hedge funds) investment assets are presented in the tables below based on the nature of the investment.



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient
As of December 31, 2017:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Domestic equity^(*)	$	155	$	323	$	—	$	—	$	478
International equity^(*)	—		166		—		—		166
Fixed income:
U.S. Treasury, government, and agency bonds	—		85		—		—		85
Corporate bonds	—		39		—		—		39
Cash equivalents and other	84		25		—		48		157
Real estate investments	3		—		—		16		19
Private equity	—		—		—		1		1
Total	$	242	$	638	$	—	$	65	$	945


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient
As of December 31, 2016:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Domestic equity^(*)	$	142	$	343	$	—	$	—	$	485
International equity^(*)	—		185		—		—		185
Fixed income:
U.S. Treasury, government, and agency bonds	—		85		—		—		85
Corporate bonds	—		41		—		—		41
Pooled funds	—		66		—		—		66
Cash equivalents and other	12		5		—		83		100
Real estate investments	4		—		—		15		19
Private equity	—		—		—		2		2
Total	$	158	$	725	$	—	$	100	$	983


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

The composition of Southern Company Gas' pension plan assets as of December 31, 2017 and 2016, along with the targets, is presented below:



	Target		2017		2016
Pension plan assets:
Equity	53	%	65	%	69	%
Fixed Income	15		19		20
Cash	2		6		1
Other	30		10		10
Balance at end of period	100	%	100	%	100	%

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

The fair values of Southern Company's (excluding Southern Company Gas) other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases.



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient		Total		Target Allocation		Actual Allocation
As of December 31, 2017:	(Level 1)		(Level 2)		(Level 3)		(NAV)
	(in millions)
Assets:
Domestic equity^(*)	$	132	$	35	$	—	$	—	$	167	37	%	40	%
International equity^(*)	47		76		—		—		123		23		23
Fixed income:											30		29
U.S. Treasury, government, and agency bonds	—		32		—		—		32
Corporate bonds	—		37		—		—		37
Pooled funds	—		55		—		—		55
Cash equivalents and other	10		—		—		—		10
Trust-owned life insurance	—		426		—		—		426
Real estate investments	16		—		—		36		52		5		5
Special situations	—		—		—		5		5		1		1
Private equity	—		—		—		20		20		4		2
Total	$	205	$	661	$	—	$	61	$	927	100	%	100	%


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient				Target Allocation		Actual Allocation
As of December 31, 2016:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Domestic equity^(*)	$	118	$	28	$	—	$	—	$	146	39	%	40	%
International equity^(*)	37		61		—		—		98		23		21
Fixed income:											29		31
U.S. Treasury, government, and agency bonds	—		24		—		—		24
Corporate bonds	—		30		—		—		30
Pooled funds	—		49		—		—		49
Cash equivalents and other	41		—		—		—		41
Trust-owned life insurance	—		382		—		—		382
Real estate investments	11		—		—		35		46		5		5
Special situations	—		—		—		5		5		1		1
Private equity	—		—		—		17		17		3		2
Total	$	207	$	574	$	—	$	57	$	838	100	%	100	%


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient		Total
As of December 31, 2017:	(Level 1)		(Level 2)		(Level 3)		(NAV)
	(in millions)
Assets:
Domestic equity^(*)	$	3	$	69	$	—	$	—	$	72
International equity^(*)	—		22		—		—		22
Fixed income:
Pooled funds	—		24		—		—		24
Cash equivalents and other	2		—		—		1		3
Total	$	5	$	115	$	—	$	1	$	121


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient		Total
As of December 31, 2016:	(Level 1)		(Level 2)		(Level 3)		(NAV)
	(in millions)
Assets:
Domestic equity^(*)	$	3	$	58	$	—	$	—	$	61
International equity^(*)	—		18		—		—		18
Fixed income:
Pooled funds	—		23		—		—		23
Cash equivalents and other	1		—		—		2		3
Total	$	4	$	99	$	—	$	2	$	105


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

The composition of Southern Company Gas' other postretirement benefit plan assets as of December 31, 2017 and 2016, along with the targets, is presented below:



	Target		2017		2016
Other postretirement benefit plan assets:
Equity	72	%	76	%	74	%
Fixed Income	24		20		23
Cash	1		2		1
Other	3		2		2
Total	100	%	100	%	100	%

Employee Savings Plan

Southern Company and its subsidiaries also sponsor 401(k) defined contribution plans covering substantially all employees and provide matching contributions up to specified percentages of an employee's eligible pay. Total matching contributions made to the plans for 2017, 2016, and 2015 were $118 million, $105 million, and $92 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

On February ~~18, 2016.~~27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes

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Southern Company and Subsidiary Companies 2017 Annual Report

Southern Company and its subsidiaries are subject to certain claims 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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, water, land, and protection of other natural resources, 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 against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements.

Environmental Matters

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 conduct studies to determine the extent of any required cleanup and have recognized the estimated costs to clean up known impacted sites in the financial statements. A liability for environmental remediation costs is recognized only when a loss is determined to be probable and reasonably estimable. The traditional electric operating companies and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have all 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 as of December 31, 2017 and 2016 was $22 million and $17 million, 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.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $52 million and $44 million as of December 31, 2017 and 2016, respectively. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power's substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

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 to have a material impact on Southern Company's financial statements.

Nuclear Fuel Disposal Costs

In 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in their spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. In 2015, Georgia Power recovered approximately $18 million, based on its ownership interests, which was credited to accounts where the original costs were charged, and used to reduce rate base, fuel, and cost of service for the benefit of customers. Also in 2015, Alabama Power recovered approximately $26 million, which was applied to reduce the cost of service for the benefit of customers.

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 and Hatch and Plant 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 October 10, 2017, Alabama Power and Georgia Power filed additional 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 and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2015 through December 31, 2017. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2017 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 back for the benefit of customers in accordance with direction from their respective PSC and, therefore, no material impact on Southern Company's net income is expected.

On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant.

FERC Matters

Market-Based Rate Authority

The traditional electric operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power filed a request for rehearing and filed their response with the FERC in 2015.

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Southern Company and Subsidiary Companies 2017 Annual Report

The ultimate outcome of these matters cannot be determined at this time.

Regulatory Matters

Alabama Power

Rate RSE

The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Retail rates remain unchanged when the WCE ranges between 5.75% and 6.21% with an adjusting point of 5.98% and eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If Alabama Power's actual retail return is above the allowed WCE range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.

At December 31, 2016, Alabama Power's retail ~~ROE~~return exceeded the allowed WCE range which resulted in Alabama Power establishing a $73 million Rate RSE refund liability. In accordance with an Alabama PSC order issued on February 14, 2017, Alabama Power applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below.

Effective in January 2017, Rate RSE increased 4.48%, or $245 million annually. At December 31, 2017, Alabama Power's actual retail return was within the allowed WCE range. On December 1, 2017, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2018. Projected earnings were within the specified range; therefore, retail ~~ROE range.~~rates under Rate RSE remained unchanged for 2018.

~~Georgia~~In conjunction with Rate RSE, Alabama Power has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time.

Rate CNP PPA

Alabama Power's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 7, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2017 through March 31, 2018. No adjustment to Rate CNP PPA is ~~required~~expected in 2018. As of December 31, 2017 and 2016, Alabama Power had an under recovered Rate CNP PPA balance of $12 million and $142 million, respectively, which is included in deferred under recovered regulatory clause revenues in the balance sheet.

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power eliminated the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," Alabama Power utilized the full amount of its $73 million Rate RSE refund liability to ~~file~~reduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a ~~general base rate case by July 1, 2016, in response to~~separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which ~~the Georgia PSC would be~~is expected to ~~determine whether~~occur within the ~~2013 ARP should~~next two to four years. Alabama Power's current depreciation study became effective January 1, 2017.

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Southern Company and Subsidiary Companies 2017 Annual Report

Rate CNP Compliance

Rate CNP Compliance allows for the recovery of Alabama Power's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be ~~continued, modified,~~recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on revenues or ~~discontinued.~~net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance in Rate CNP Compliance to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2017.

On December 5, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2018 the factors associated with Alabama Power's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered amounts associated with 2018 will be reflected in the 2019 filing. As of December 31, 2017 and 2016, Alabama Power had a deferred under recovered regulatory clause revenues balance of $17 million and $9 million, respectively.

Integrated Resource Plan

~~To comply with the April 16, 2015 effective date~~See "Environmental Matters" herein for additional information regarding proposed and final EPA rules and regulations, including revisions to ELG for steam electric power plants and additional regulations of ~~the MATS rule, Plant Branch Units 1, 3,~~CCR and ~~4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and~~ CO_{2 (122 MWs) were retired and operations were discontinued at Plant Mitchell Unit 3 (155 MWs) by April 15, 2015, and Plant Kraft Units 1 through 4 (316 MWs) were retired on October 13, 2015. The switch to natural gas as the primary fuel was completed at Plant Yates Units 6 and 7 by June 2015 and at Plant Gaston Units 1 through 4 by December 2015.}.

InAdditionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.

The Georgia ~~Power requested~~PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 as of its retirement date, to a regulatory asset to be amortized over a period equal to the unit's remaining useful life. Georgia Power also requested that the Georgia PSC approve the deferral of the costand costs associated with materials and supplies remaining at the unit retirement ~~dates~~date to a regulatory ~~asset,~~asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in Georgia Power's 2019 base rate case.

In 2017, Georgia Power filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to be ~~amortized over~~in operation by the end of 2019. Georgia Power also filed for and received approval to develop several solar generation projects to fulfill the approved self-build capacity.

In the 2016 IRP, the Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a ~~period deemed appropriate~~future generation site in Stewart County, Georgia. On March 7, 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. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia ~~PSC.~~PSC in a future Georgia Power rate case.

Storm Damage Recovery

Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. Hurricanes Irma and Matthew caused significant damage to Georgia Power's transmission and distribution facilities during September 2017 and October 2016, respectively. The ~~decertification~~incremental restoration costs related to these hurricanes deferred in Georgia Power's regulatory

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Southern Company and ~~retirement~~Subsidiary Companies 2017 Annual Report

asset for storm damage totaled approximately $260 million. At December 31, 2017, the total balance in Georgia Power's regulatory asset related to storm damage was $333 million. The rate of ~~these units~~storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial ~~statements; however,~~statements. See Note 3 to the financial statements under "Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information regarding Georgia Power's storm damage reserve.

Gulf Power

On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request in 2016 to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes. Gulf Power also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause.

The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to Gulf Power's base rates. Under the terms of the 2017 Rate Case Settlement Agreement, by March 1, 2018, Gulf Power must identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to Gulf Power's base rates and $15.6 million to Gulf Power's environmental cost recovery rates effective beginning the first calendar month following approval.

The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through Gulf Power's fuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and Gulf Power will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.

The ultimate outcome ~~depends~~of these matters cannot be determined at this time.

Mississippi Power

On February 7, 2018, Mississippi Power revised its annual projected PEP filing for 2018 to reflect the impacts of the Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%. The ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia ~~PSC's orders in the 2016 IRP~~ and ~~next general base rate case.~~handle customer billing functions. Atlanta Gas Light earns revenue for its

~~Additionally, the 2016 IRP included a Renewable Energy Development Initiative requesting~~

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

distribution services by charging rates to 525 MWs of renewable resources utilizing market-based prices established through a competitive bidding process to expand Georgia Power's existing renewable initiatives, including the Advanced Solar Initiative.

~~A decision from~~its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically.

With the exception of Atlanta Gas Light, 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 and energy efficiency plans. See Note 1 to the financial statements under "Cost of Natural Gas" for additional information.

Regulatory Infrastructure Programs

Certain of Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs are 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. Initial program lengths range from nine to 10 years, with completion dates ranging from 2020 through 2025. The total expected investment under these programs for 2018 is $395 million.

Base Rate Cases

The Illinois Commerce Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commerce Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which Nicor Gas expects to file by the end of the second quarter 2018.

On December 1, 2017, Atlanta Gas Light filed its 2018 annual rate adjustment with the Georgia PSC. If approved, Atlanta Gas Light's annual base rate revenues will increase by $22 million, effective June 1, 2018. Atlanta Gas Light will file a revised rate adjustment to incorporate the effects of the Tax Reform Legislation in the first quarter 2018. The Georgia PSC is expected to rule on the ~~2016 IRP is expected~~revised requested increase in the ~~third~~second quarter ~~2016.~~ 2018.

The ultimate outcome of these matters cannot be determined at this time.

Fuel Cost Recovery

~~Georgia Power has~~The traditional electric operating companies each have established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved a reduction in Georgia Power's total annual billings of approximately $567 million effective June 1, 2012, with an additional $122 million reduction effective January 1, 2013 through June 1, 2014. Under an Interim Fuel Rider, Georgia Power continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power's fuel cost recovery includes costs associated with a natural gas hedging program, as approved by the Georgia PSC in 2015, allowing it to use an array of derivative instruments within a 48-month time horizon effective January 1, 2016. See Note 11 under "Energy-Related Derivatives" for additional information. On December 15, 2015, the Georgia PSC approved Georgia Power's request to lower annual billings by approximately $350 million effective January 1, 2016.

Georgia Power's over recovered fuel balance totaled approximately $116 million at December 31, 2015 and is included in current liabilities and other deferred liabilities. At December 31, 2014, Georgia Power's under recovered fuel balance totaled approximately $199 million and was included in current assets and other deferred charges and assets.

their respective state PSCs. Fuel cost recovery revenues ~~as recorded on the financial statements~~ are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.

~~Storm Damage Recovery~~

Kemper County Energy Facility

The Kemper County energy facility was approved by the Mississippi PSC as an IGCC facility in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of the Initial DOE Grants and ~~recovers certain costs~~excluding the Cost Cap Exceptions. The combined cycle and associated common facilities portions of the Kemper County energy facility were placed in service in August 2014. In December 2015, the Mississippi PSC issued the In-Service Asset Rate Order, authorizing rates that provided for the recovery of approximately $126 million annually related to ~~damages from major storms~~the assets previously placed in service.

On June 21, 2017, the Mississippi PSC stated its intent to issue the Kemper Settlement Order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as ~~mandated by the Georgia PSC. Beginning January 1, 2014, Georgia Power is accruing $30 million annually under the 2013 ARP that is recoverable through base~~a natural

~~II-88~~

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Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

~~rates. As~~gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility. The Kemper Settlement Order established the Kemper Settlement Docket for the purposes of pursuing a global settlement of the related costs.

On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. At the time of project suspension, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants. In the aggregate, Mississippi Power had incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine.

Total pre-tax charges to income related to the Kemper County energy facility were $3.4 billion ($2.4 billion after tax) for the year ended December 31, ~~2015 and~~2017. In the aggregate, since the Kemper County energy facility project started, Mississippi Power has incurred charges of $6.2 billion ($4.1 billion after tax) through December 31, 2014, the balance in the regulatory asset related to storm damage was $92 million and $98 million, respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $62 million and $68 million included in other regulatory assets, deferred, respectively. Georgia Power expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs. 2017.

As a result of the ~~regulatory treatment, costs~~Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.

See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.

Litigation

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to ~~storms are generally not expected~~the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the

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Southern Company and Subsidiary Companies 2017 Annual Report

plaintiffs filed notice of an appeal. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's results of operations, financial ~~statements.~~condition, and liquidity. Southern Company intends to vigorously defend itself in this matter and the ultimate outcome of this matter cannot be determined at this time.

Construction Program

Overview

The subsidiary companies of Southern Company 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, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. 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 their regulated rates. The Southern Company system's construction program is currently estimated to total approximately $9.4 billion, $9.3 billion, $8.4 billion, $7.0 billion, and $6.9 billion for 2018, 2019, 2020, 2021, and 2022, respectively.

Nuclear Construction

Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy

In 2008, Georgia Power, acting for itself and as agent for ~~Oglethorpe Power Corporation (OPC),~~ the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, Vogtle ~~Owners),~~Owners, entered into an agreement with a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc., a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. (CB&I) (Westinghouse and Stone & Webster, Inc., collectively, Contractor), pursuant to which the ~~Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately~~ ~~1,100~~ ~~MWs each) and related facilities at Plant~~ Vogtle ~~(Vogtle~~ 3 and 4 ~~Agreement).~~

Agreement. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price ~~that is~~ subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. ~~The~~Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In the first quarter 2016, Westinghouse delivered to the Vogtle Owners a total of $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement.

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Southern Company and Subsidiary Companies 2017 Annual Report

On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, ~~also provides~~Toshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share was approximately $1.7 billion. The Guarantee Settlement Agreement provided for ~~liquidated damages upon~~a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, Georgia Power, the other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of Georgia Power, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and Georgia Power and the other Vogtle Owners surrendered the Westinghouse Letters of Credit.

Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement, which was amended and restated on July 20, 2017. On July 20, 2017, the bankruptcy court approved the EPC Contractor's ~~failure~~motion seeking authorization to ~~fulfill~~(i) enter into the ~~schedule~~Vogtle Services Agreement, (ii) assume and ~~performance guarantees, subject~~assign to ~~a cap. In addition,~~the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Vogtle Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, ~~provides for limited cost sharing~~became effective upon approval by the DOE on July 27, 2017. The Vogtle Services Agreement 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 ~~for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to~~upon 30 days' written notice.

Effective October 23, 2017, Georgia Power, ~~(based~~acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on ~~Georgia Power's ownership interest) of approximately $114 million.~~Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally ~~(and not~~(not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to ~~the Contractor~~Bechtel under the ~~Vogtle 3 and 4~~Bechtel Agreement. ~~Georgia Power's proportionate share is~~ ~~45.7%~~.

On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from CB&I (Acquisition). In connection with the Acquisition, Stone & Webster, Inc. changed its name to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and Stone & Webster, Inc. have been guaranteed by Toshiba Corporation, Westinghouse's parent company, and CB&I's The Shaw Group Inc., respectively. Subject to the consent of the DOE, in connection with the Acquisition and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. will be terminated. The guarantee of Toshiba Corporation remains in place. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, on January 13, 2016, as a result of recent credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $900 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.

The Vogtle Owners may terminate the ~~Vogtle 3 and 4~~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 costs. The Contractor~~termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the ~~Vogtle 3 and 4~~Bechtel Agreement under certain circumstances, including certain Vogtle Owner ~~suspension or delays~~suspensions of ~~work, action by a governmental authority to permanently stop~~ work, certain breaches of the ~~Vogtle 3 and 4~~Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.

~~In 2009,~~On November 2, 2017, the ~~NRC issued~~Vogtle Owners entered into an ~~Early Site Permit and Limited Work Authorization which allowed limited work~~amendment to ~~begin on~~their joint ownership agreements for Plant Vogtle Units 3 and ~~4. The NRC certified~~4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the ~~Westinghouse Design Control Document, as amended (DCD), for~~Vogtle Joint Ownership Agreements, the ~~AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt~~holders of at least 90% of the ~~COLs allowed full~~ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction ~~to begin. There have been technical and procedural challenges~~if certain adverse events occur, including (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction ~~and licensing~~ of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the ~~federal~~primary construction contractor and ~~state level,~~(ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. 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.

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Southern Company and ~~additional challenges may arise as construction proceeds.~~Subsidiary Companies 2017 Annual Report

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4.4 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 nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff ~~by including~~up to the ~~related CWIP accounts in rate base during the construction period. The~~certified capital cost of $4.418 billion. As of December 31, 2017, Georgia ~~PSC approved an initial NCCR tariff~~Power had recovered approximately $1.6 billion of ~~approximately $223 million effective~~financing costs. On January ~~1, 2011, as well as increases~~30, 2018, Georgia Power filed to decrease the NCCR tariff ofby approximately ~~$35 million,~~ $50 million, ~~$60 million, $27~~effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, the Customer Refunds ordered by the Georgia PSC aggregating approximately $188 million, and ~~$19 million effective January 1, 2012, 2013, 2014, 2015,~~the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and ~~2016, respectively.~~

~~II-89~~

~~Table~~will be paid in three installments of ~~ContentsIndex~~$25 to ~~Financial Statements~~each retail customer no later than the third quarter 2018.

~~NOTES (continued)~~

~~Southern Company and Subsidiary Companies 2015 Annual Report~~

Georgia Power is required to file semi-annual ~~Vogtle Construction Monitoring (VCM)~~VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected construction capital costs to be borne by Georgia Power increase by 5% above the certified cost or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. In February 2013, Georgia Power requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the staff of the Georgia PSC ~~Staff (Staff)~~ 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.

On ~~April 15, 2015,~~December 20, 2016, the Georgia PSC ~~issued~~voted to approve a ~~procedural order~~settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the ~~twelfth~~fifteenth VCM report. On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report ~~which included a requested amendment (Requested Amendment)~~and modifying 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 ~~the~~ Plant Vogtle Units 3 and ~~4 certificate to reflect~~4: (i) none of the ~~Contractor's revised forecast for completion~~$3.3 billion of ~~Plant Vogtle Units 3~~costs incurred through December 31, 2015 and ~~4 (second quarter~~reflected in the fourteenth VCM report should be disallowed from rate base on the basis of ~~2019~~imprudence; (ii) the Contractor Settlement Agreement was reasonable and ~~second quarter~~prudent and none of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated Vogtle Owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuantamounts paid pursuant to the ~~Georgia PSC's procedural order,~~Contractor Settlement Agreement should be disallowed from rate base on the ~~Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion~~basis of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, anyimprudence; (iii) (a) capital costs incurred ~~by Georgia Power in excess of the certified amount will~~up to $5.680 billion would be ~~included in rate base, provided Georgia Power shows the costs~~presumed to be reasonable and ~~prudent. Financing costs up to~~prudent with the ~~certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costs~~burden of proof on any ~~construction-related~~party challenging such costs, ~~in excess~~(b) Georgia Power would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the ~~$4.4 billion certified amount are expected to be recovered through AFUDC.~~

~~In 2012, the Vogtle Owners and the Contractor commenced litigation regarding the costs associated with design changes to the DCD and the delays in the timing~~impact of ~~approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs~~payments received under the terms of the Vogtle 3 and 4 Agreement. The Contractor also asserted that it was entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended claim alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. In June 2015, the Contractor updated its estimated damages to an aggregate (based on Georgia Power's ownership interest) of approximately $714 million (in 2015 dollars). The case was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation).

On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation. Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The ContractorGuarantee Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4;Customer Refunds) is found reasonable; (iv) provide that delay liquidated damages will now commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4, rather than the original guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $120 million has been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. Further, subsequent to December 31, 2015, Georgia Power paid approximately $121 million under the terms of the Contractor Settlement Agreement. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the settlement and in connection with the Acquisition: (i) Westinghouse has engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. have entered into mutual releases of any and all claims arising out of events or circumstances in connection with the 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 ~~occurred~~the revised cost forecast does not represent a cost cap and that prudence decisions on orcost 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 $20 million in 2016 and $25 million in 2017 and are estimated to have negative earnings impacts of approximately $120 million in 2018 and an aggregate of $585 million from 2019 to 2022. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Georgia PSC reserve the right to reconsider the decision to continue construction.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. Georgia Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of operations, financial condition, and liquidity.

The IRS allocated PTCs to each of Plant Vogtle Units 3 and 4, which originally required the applicable unit to be placed in service before 2021. Under the ~~date~~Bipartisan Budget Act of 2018, Plant Vogtle Units 3 and 4 continue to qualify for PTCs. The nominal value of Georgia Power's portion of the ~~Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.~~PTCs is approximately $500 million per unit.

~~II-90~~

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~~NOTES~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

OnIn its January ~~21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to~~11, 2018 order, the Georgia PSC ~~for its review. On February 2, 2016, the Georgia PSC ordered Georgia Power to file supplemental information by April 5, 2016 in support~~also approved $542 million of ~~the Contractor Settlement Agreement and Georgia Power's position that all construction costs to date have been prudently incurred and that the current estimated in-service~~ capital ~~cost and schedule are reasonable. Following Georgia Power's filing under the order, the Staff will conduct a review of all~~ costs incurred ~~related~~during the seventeenth VCM reporting period (January 1, 2017 to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement and the Staff is authorized to engage in related settlement discussions with Georgia Power and any intervenors.

The order provides that the Staff is required to report to the Georgia PSC by October 5, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.

June 30, 2017). The Georgia PSC has approved ~~thirteen~~seventeen VCM reports covering the periods through June 30, ~~2015,~~2017, including total construction capital costs incurred ~~which~~ through that date ~~totaled $3.1~~of $4.4 billion. ~~On February 26, 2016,~~ Georgia Power ~~filed~~expects to file its ~~fourteenth~~eighteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power ison February 28, 2018 requesting approval of ~~$160~~approximately $450 million of construction capital costs (before payments received under the Guarantee Settlement Agreement and the Customer Refunds) incurred ~~during that period. Georgia Power anticipates to incur average financing costs of approximately $27 million per month~~ from January 2016 until Plant Vogtle Units 3 and 4 are placed in service. The updated in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion.July 1, 2017 through December 31, 2017. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately ~~$3.6~~$4.8 billion as of December 31, ~~2015.~~2017, or $3.3 billion net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.

The ultimate outcome of these matters cannot be determined at this time.

Cost and Schedule



	(in billions)
Project capital cost forecast	$	7.3
Net investment as of December 31, 2017	(3.4		)
Remaining estimate to complete	$	3.9

Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.

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 ~~DCD~~Westinghouse Design Control Document and the ~~COLs,~~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 ~~issues~~matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, ~~as construction proceeds,~~ 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 either to the Vogtle Owners or the Contractor or to both.~~

As construction continues, the risk remains that challenges with Contractor performance including fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.

Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.costs.

The ultimate outcome of these matters cannot be determined at this time.

~~Gulf~~Other Matters

The ultimate outcome of these matters cannot be determined at this time.

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Southern Company and Subsidiary Companies 2017 Annual Report

Income Tax Matters

Federal Tax Reform Legislation

See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.

The ultimate outcome of these matters cannot be determined at this time.

Bonus Depreciation

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Southern Company and Subsidiary Companies 2017 Annual Report

Tax Credits

Southern Power

Other Matters

~~Retail Base~~Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. 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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as standards for air, water, land, and protection of other natural resources, 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.

Litigation

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Investments in Leveraged Leases

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Southern Company and Subsidiary Companies 2017 Annual Report

Natural Gas Storage

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Utility Regulation

Kemper County Energy Facility Rate ~~Case~~Recovery

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Southern Company and Subsidiary Companies 2017 Annual Report

See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.

Accounting for Income Taxes

Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of the Company's current financial position and result of operations, including currently available information about future years, to estimate when future taxable income will be realized.

Federal Tax Reform Legislation

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Southern Company and Subsidiary Companies 2017 Annual Report

to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Regulatory Matters" and "Current and Deferred Income Taxes," respectively, for additional information.

Asset Retirement Obligations

The liability for AROs primarily relates to facilities that are subject to the CCR Rule, principally ash ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded as the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.

The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the traditional electric operating companies will continue to periodically update these cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.

Given the significant judgment involved in estimating AROs, Southern Company considers the liabilities for AROs to be critical accounting estimates.

Pension and Other Postretirement Benefits

Key elements in determining Southern Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, Southern Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. Beginning in 2016, Southern Company adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost

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Southern Company and Subsidiary Companies 2017 Annual Report

component of net periodic pension and other postretirement benefit plan expense decreased by approximately $96 million in 2016.



Change in Assumption	Increase/(Decrease) in Total Benefit Expense for 2018	Increase/(Decrease) in Projected Obligation for Pension Plan at December 31, 2017	Increase/(Decrease) in Projected Obligation for Other Postretirement Benefit Plans at December 31, 2017
	(in millions)
25 basis point change in discount rate	$40/$(38)	$504/$(476)	$68/$(65)
25 basis point change in salaries	$24/$(23)	$119/$(115)	$–/$–
25 basis point change in long-term return on plan assets	$33/$(33)	N/A	N/A

N/A – Not applicable

See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.

Goodwill and Other Intangible Assets

Derivatives and Hedging Activities

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Southern Company and Subsidiary Companies 2017 Annual Report

the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);

events specific to a given counterparty; and

the impact of Southern Company's nonperformance risk on its liabilities.

Contingent Obligations

Recently Issued Accounting Standards

Revenue

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

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Southern Company and Subsidiary Companies 2017 Annual Report

Leases

Other

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. Southern Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.

On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. Southern Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.

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Southern Company and Subsidiary Companies 2017 Annual Report

FINANCIAL CONDITION AND LIQUIDITY

Overview

Earnings in all periods presented were negatively affected by charges associated with the Kemper IGCC; however, Southern Company's financial condition remained stable at December 31, 2017.

The Southern Company system's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. The Southern Company system's capital expenditures and other investing activities include investments to meet projected long-term demand requirements, including to build new electric generation facilities, to maintain existing electric generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing electric generating units, to expand and improve electric transmission and distribution facilities, to update and expand natural gas distribution systems, and for restoration following major storms. Operating cash flows provide a substantial portion of the Southern Company system's cash needs. For the three-year period from 2018 through 2020, Southern Company's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. Southern Company plans to finance future cash needs in excess of its operating cash flows primarily by accessing borrowings from financial institutions and through debt and equity issuances in the capital markets. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.

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Southern Company and Subsidiary Companies 2017 Annual Report

Sources of Capital

On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note 3 to the financial statements under "Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

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Southern Company and Subsidiary Companies 2017 Annual Report

well as the securities registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.

At December 31, 2017, Southern Company and its subsidiaries had approximately $2.1 billion of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2017 were as follows:



	Expires												Executable Term Loans				Expires Within One Year
Company	2018		2019		2020		2022		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)
Southern Company^(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—	$	—	$	—	$	—
Alabama Power	35		—		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	30		25		225		—		280		280		45		—		20		10
Mississippi Power	100		—		—		—		100		100		—		—		—		100
Southern Power Company^(b)	—		—		—		750		750		728		—		—		—		—
Southern Company Gas^(c)	—		—		—		1,900		1,900		1,890		—		—		—		—
Other	30		—		—		—		30		30		20		—		20		10
Southern Company Consolidated	$	195	$	25	$	725	$	7,200	$	8,145	$	8,094	$	65	$	—	$	40	$	155


(a)	Represents the Southern Company parent entity.


(b)	Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $19 million remains unused at December 31, 2017.


(c)	Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.

In ~~2013,~~May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the ~~Florida PSC voted~~maturity dates from 2020 to ~~approve~~2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018.

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Southern Company and Subsidiary Companies 2017 Annual Report

Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a ~~settlement agreement~~new multi-year credit arrangement with $1.4 billion and $500 million currently allocated to Southern Company Gas Capital and Nicor Gas, respectively, maturing in 2022. Pursuant to the new multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. In September 2017, Alabama Power also amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020. In November 2017, Gulf Power amended $195 million of its multi-year credit arrangements to extend the maturity dates from 2017 and 2018 to 2020 and Mississippi Power amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018.

Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, 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 December 31, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

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Southern Company and Subsidiary Companies 2017 Annual Report

Details of short-term borrowings were as follows:



	Short-term Debt at the End of the Period				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)
December 31, 2017:
Commercial paper	$	1,832	1.8	%	$	2,117	1.3	%	$	2,946
Short-term bank debt	607		2.3	%	555		2.1	%	1,020
Total	$	2,439	1.9	%	$	2,672	1.5	%
December 31, 2016:
Commercial paper	$	1,909	1.1	%	$	976	0.8	%	$	1,970
Short-term bank debt	123		1.7	%	176		1.7	%	500
Total	$	2,032	1.1	%	$	1,152	1.1	%
December 31, 2015:
Commercial paper	$	740	0.7	%	$	842	0.4	%	$	1,563
Short-term bank debt	500		1.4	%	444		1.1	%	795
Total	$	1,240	0.9	%	$	1,286	0.5	%


(*)	Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2017, 2016, and 2015.

In addition to the short-term borrowings of Southern Power Company included in the table above, at December 31, 2016 and 2015, Southern Power Company subsidiaries had credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. The Project Credit Facilities were fully repaid in January 2017. For the year ended December 31, 2016, the Project Credit Facilities had a maximum amount outstanding of $828 million and an average amount outstanding of $566 million at a weighted average interest rate of 2.1% and had total amounts outstanding of $209 million at a weighted average interest rate of 2.1% at December 31, 2016. For the year ended December 31, 2015, the Project Credit Facilities had a maximum amount outstanding of $137 million and an average amount outstanding of $13 million at a weighted average interest rate of 2.0% and had total amounts outstanding of $137 million at a weighted average interest rate of 2.0% at December 31, 2015.

The 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.

Financing Activities

During 2017, Southern Company issued approximately 14.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $659 million.

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Southern Company and Subsidiary Companies 2017 Annual Report

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the year ended December 31, 2017:



Company	Senior Note Issuances		Senior Note Maturities and Redemptions		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)	$	300	$	400	$	—	$	—	$	950		$	400
Alabama Power	1,100		525		—		36		—			—
Georgia Power	1,350		450		65		65		370			17
Gulf Power	300		85		—		—		6			—
Mississippi Power	—		35		—		—		40			962
Southern Power	525		500		—		—		43			18
Southern Company Gas^(c)	450		—		—		—		400			22
Other	—		—		—		—		—			15
Elimination^(d)	—		—		—		—		(40		)	(602		)
Southern Company Consolidated	$	4,025	$	1,995	$	65	$	101	$	1,769		$	832


(a)	Includes reductions in capital lease obligations resulting from cash payments under capital leases.


(b)	Represents the Southern Company parent entity.


(c)	The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas.


(d)	Includes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements.

In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.

Also in August 2017, Southern Company repaid at maturity $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes.

In November 2017, Southern Company issued $450 million aggregate principal amount of Series 2017B 5.25% Junior Subordinated Notes due December 1, 2077.

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Southern Company and Subsidiary Companies 2017 Annual Report

Subsequent to December 31, 2017, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.

As reflected in the table above under other long-term debt issuances, in September 2017, Georgia Power also issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.

In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.

Credit Rating Risk

At December 31, 2017, 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.

The maximum potential collateral requirements under these contracts at December 31, 2017 were as follows:



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	40
At BBB- and/or Baa3	$	665
At BB+ and/or Ba1^(*)	$	2,390


(*)	Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million.

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Southern Company and Subsidiary Companies 2017 Annual Report

impact the cost at which they do so.

On March 1, 2017, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Ba1 from Baa3.

On March 20, 2017, Moody's revised its rating outlook for Georgia Power from stable to negative.

On March 30, 2017, Fitch Ratings, Inc. placed the ratings of Southern Company, Georgia Power, and Mississippi Power on rating watch negative.

On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade. On September 21, 2017, Moody's revised its rating outlook for Mississippi Power from under review to stable.

On January 19, 2018, Moody's revised its rating outlooks for Southern Company and Alabama Power from stable to negative.

Market Price Risk

The Southern Company system is 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, the applicable company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the applicable 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.

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Southern Company and Subsidiary Companies 2017 Annual Report



	2017 Changes			2016 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	41		$	(213	)
Acquisitions	—			(54		)
Contracts realized or settled	(8		)	141
Current period changes^(a)	(196		)	171
Contracts outstanding at the end of the period, assets (liabilities), net^(b)	$	(163	)	$	45


(a)	Current period changes also include the changes in fair value of new contracts entered into during the period, if any.


(b)	Excludes premium and intrinsic value associated with weather derivatives of $11 million at December 31, 2017 and includes premium and intrinsic value associated with weather derivatives of $4 million at December 31, 2016.

The net hedge volumes of energy-related derivative contracts were 621 million mmBtu and 500 million mmBtu for the years ended December 31, 2017 and 2016, respectively.

For the traditional electric operating companies and Southern Power, the weighted average swap contract cost above or (below) market prices was approximately $0.15 per mmBtu as of December 31, 2017 and $(0.05) per mmBtu as of December 31, 2016. The majority of the natural gas hedge gains and losses are recovered through the traditional electric operating companies' fuel cost recovery clauses.

At December 31, 2017 and 2016, substantially all of the ~~intervenors~~Southern Company system's energy-related derivative contracts were designated as regulatory hedges and were related to ~~Gulf Power's retail base rate case (Gulf Power Settlement Agreement). Under~~ the ~~terms~~applicable company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. 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 and were not material for any year presented.

The Southern Company system uses exchange-traded market-observable contracts, which are categorized as Level 1 of the ~~Gulf Power Settlement Agreement, Gulf Power (1) increased base rates approximately $35 million annually effective January 2014~~fair value hierarchy, and ~~subsequently increased base rates approximately $20 million annually effective January 2015; (2) continued its current authorized retail ROE midpoint (10.25%)~~over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and ~~range (9.25% – 11.25%); and (3)~~thus fall into Level 2 of the fair value hierarchy. See Note 10 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts at December 31, 2017 were as follows:



	Fair Value Measurements
	December 31, 2017
	Total Fair Value			Maturity
	Total Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	(148	)	$	(71	)	$	(59	)	$	(18	)
Level 2	(15		)	(30		)	13			2
Level 3	—			—			—			—
Fair value of contracts outstanding at end of period	$	(163	)	$	(101	)	$	(46	)	$	(16	)

The Southern Company system is ~~accruing a return similar~~exposed to ~~AFUDC on certain transmission system upgrades placed into service after January 2014 until Gulf Power's next base rate adjustment date or January 1, 2017, whichever comes first.~~

~~The Gulf Power Settlement Agreement also includes a self-executing adjustment mechanism that will increase the authorized retail ROE midpoint and range by 25 basis points~~market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. The Southern Company system only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the ~~30-year treasury yield rate increases~~Southern Company system does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements.

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Southern Company and Subsidiary Companies 2017 Annual Report

Capital Requirements and Contractual Obligations

The Southern Company system's construction program is currently estimated to total approximately $9.4 billion for 2018, $9.3 billion for 2019, $8.4 billion for 2020, $7.0 billion for 2021, and $6.9 billion for 2022. These amounts include expenditures of approximately $1.2 billion, $1.0 billion, $0.9 billion, $0.7 billion, and $0.4 billion for the construction of Plant Vogtle Units 3 and 4 in 2018, 2019, 2020, 2021, and 2022, respectively, and an average of approximately $1.3 billion per year for 2018 through 2022 for Southern Power's planned expenditures for plant acquisitions and placeholder growth. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $1.1 billion, $0.3 billion, $0.4 billion, $0.5 billion, and $0.5 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO₂ emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and " – Global Climate Issues" 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 the environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at ~~least 75 basis points above 3.7947%~~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; 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 execute its growth strategy. See Note 12 to the financial statements under "Southern Power" for additional information regarding Southern Power's plant acquisitions.

In addition, the construction program includes the development and construction of new electric generating facilities with designs that have not been previously constructed, which may result in revised estimates during construction. The ability to control costs and avoid cost overruns during the development, construction, and operation of new facilities is subject to a ~~consecutive six-month period.~~number of factors, including, but not limited to, changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance. See Note 3 to the financial statements under "Nuclear Construction" for information regarding additional factors that may impact construction expenditures.

~~II-91~~Table of Contents Index to Financial Statements

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Southern Company and Subsidiary Companies 2017 Annual Report

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Southern Company and Subsidiary Companies 2017 Annual Report

Contractual Obligations

The Southern Company system's contractual obligations at December 31, 2017 were as follows:



	2018		2019- 2020		2021- 2022		After 2022		Total
	(in millions)
Long-term debt^(a) —
Principal	$	3,865	$	6,293	$	5,206	$	32,610	$	47,974
Interest	1,782		3,286		2,793		27,535		35,396
Preferred stock dividends of subsidiaries^(b)	16		33		33		—		82
Financial derivative obligations^(c)	493		198		37		5		733
Operating leases^(d)	149		232		178		968		1,527
Capital leases^(d)	39		43		20		232		334
Unrecognized tax benefits^(e)	18		—		—		—		18
Pipeline charges, storage capacity, and gas supply^(f)	813		968		714		2,294		4,789
Asset management agreements^(g)	9		6		—		—		15
Purchase commitments—
Capital^(h)	9,016		16,905		12,749		—		38,670
Fuel⁽ⁱ⁾	3,156		3,573		1,927		5,588		14,244
Purchased power^(j)	424		884		886		3,716		5,910
Other^(k)	407		713		434		2,745		4,299
Trusts —
Nuclear decommissioning^(l)	5		11		11		94		121
Pension and other postretirement benefit plans^(m)	137		275		—		—		412
Total	$	20,329	$	33,420	$	24,988	$	75,787	$	154,524

(a)


(b)	Represents preferred stock of subsidiaries. Preferred stock does not mature; therefore, amounts are provided for the next five years only.


(c)	See Notes 1 and 11 to the financial statements.


(d)	Excludes PPAs that are accounted for as leases and included in "Purchased power."


(e)	See Note 5 to the financial statements under "Unrecognized Tax Benefits" for additional information.

(f)


(g)	Represents fixed-fee minimum payments for asset management agreements associated with wholesale gas services.

(h)

(i)


(j)	Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities.


(k)	Includes LTSAs, contracts for the procurement of limestone, contractual environmental remediation liabilities, and operation and maintenance agreements. LTSAs include price escalation based on inflation indices.

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Southern Company and Subsidiary Companies 2017 Annual Report

(l)

(m)

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Southern Company and Subsidiary Companies 2017 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

Southern Company's 2017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the wholesale business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plans, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates of construction projects, completion of announced acquisitions or dispositions, filings with state and federal regulatory authorities, impacts of the Tax Reform Legislation, federal and state income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of Southern Company and its subsidiaries;

current and future litigation or regulatory investigations, proceedings, or inquiries;

the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;

available sources and costs of natural gas and other fuels;

limits on pipeline capacity;

transmission constraints;

effects of inflation;

the ability to control costs and avoid cost overruns during the development, construction, and operation of facilities, which include the development and construction of generating facilities with designs that have not been previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance;

the ability to construct facilities in accordance with the requirements of permits and licenses (including satisfaction of NRC requirements), to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;

investment performance of the Southern Company system's employee and retiree benefit plans and nuclear decommissioning trust funds;

advances in technology;

ongoing renewable energy partnerships and development agreements;

state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;

the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;

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Southern Company and Subsidiary Companies 2017 Annual Report

legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;

litigation related to the Kemper County energy facility;

the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;

the inherent risks involved in transporting and storing natural gas;

the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;

internal restructuring or other restructuring options that may be pursued;

the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;

the ability to obtain new short- and long-term contracts with wholesale customers;

the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or physical attack and the threat of physical attacks;

interest rate fluctuations and financial market conditions and the results of financing efforts;

changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

the ability of Southern Company's electric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;

impairments of goodwill or long-lived assets;

the effect of accounting pronouncements issued periodically by standard-setting bodies; and

other factors discussed elsewhere herein and in other reports filed by Southern Company from time to time with the SEC.

Southern Company expressly disclaims any obligation to update any forward-looking statements.

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CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2017, 2016, and 2015

Southern Company and Subsidiary Companies 2017 Annual Report



	2017			2016			2015
	(in millions)
Operating Revenues:
Retail electric revenues	$	15,330		$	15,234		$	14,987
Wholesale electric revenues	2,426			1,926			1,798
Other electric revenues	681			698			657
Natural gas revenues	3,791			1,596			—
Other revenues	803			442			47
Total operating revenues	23,031			19,896			17,489
Operating Expenses:
Fuel	4,400			4,361			4,750
Purchased power	863			750			645
Cost of natural gas	1,601			613			—
Cost of other sales	513			260			—
Other operations and maintenance	5,481			5,240			4,416
Depreciation and amortization	3,010			2,502			2,034
Taxes other than income taxes	1,250			1,113			997
Estimated loss on Kemper IGCC	3,362			428			365
Total operating expenses	20,480			15,267			13,207
Operating Income	2,551			4,629			4,282
Other Income and (Expense):
Allowance for equity funds used during construction	160			202			226
Earnings from equity method investments	106			59			—
Interest expense, net of amounts capitalized	(1,694		)	(1,317		)	(840		)
Other income (expense), net	(55		)	(93		)	(39		)
Total other income and (expense)	(1,483		)	(1,149		)	(653		)
Earnings Before Income Taxes	1,068			3,480			3,629
Income taxes	142			951			1,194
Consolidated Net Income	926			2,529			2,435
Less:
Dividends on preferred and preference stock of subsidiaries	38			45			54
Net income attributable to noncontrolling interests	46			36			14
Consolidated Net Income Attributable to Southern Company	$	842		$	2,448		$	2,367
Common Stock Data:
Earnings per share —
Basic	$	0.84		$	2.57		$	2.60
Diluted	0.84			2.55			2.59
Average number of shares of common stock outstanding — (in millions)
Basic	1,000			951			910
Diluted	1,008			958			914

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2017, 2016, and 2015

Southern Company and Subsidiary Companies 2017 Annual Report



	2017			2016			2015
	(in millions)
Consolidated Net Income	$	926		$	2,529		$	2,435
Other comprehensive income:
Qualifying hedges:
Changes in fair value, net of tax of $34, $(84), and $(8), respectively	57			(136		)	(13		)
Reclassification adjustment for amounts included in net income, net of tax of $(37), $43, and $4, respectively	(60		)	69			6
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax of $6, $10, and $(1), respectively	17			13			(2		)
Reclassification adjustment for amounts included in net income, net of tax of $(6), $3, and $4, respectively	(23		)	4			7
Total other comprehensive income (loss)	(9		)	(50		)	(2		)
Less:
Dividends on preferred and preference stock of subsidiaries	38			45			54
Comprehensive income attributable to noncontrolling interests	46			36			14
Consolidated Comprehensive Income Attributable to Southern Company	$	833		$	2,398		$	2,365

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2017, 2016, and 2015

Southern Company and Subsidiary Companies 2017 Annual Report



	2017			2016			2015
				(in millions)
Operating Activities:
Consolidated net income	$	926		$	2,529		$	2,435
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	3,457			2,923			2,395
Deferred income taxes	166			(127		)	1,404
Collateral deposits	(4		)	(102		)	—
Allowance for equity funds used during construction	(160		)	(202		)	(226		)
Pension and postretirement funding	(2		)	(1,029		)	(7		)
Settlement of asset retirement obligations	(177		)	(171		)	(37		)
Stock based compensation expense	109			121			99
Hedge settlements	6			(233		)	(17		)
Estimated loss on Kemper IGCC	3,179			428			365
Income taxes receivable, non-current	(47		)	(122		)	(413		)
Other, net	(109		)	(99		)	49
Changes in certain current assets and liabilities —
-Receivables	(199		)	(544		)	243
-Fossil fuel for generation	36			178			61
-Natural gas for sale	36			(226		)	—
-Other current assets	(143		)	(206		)	(152		)
-Accounts payable	(280		)	301			(353		)
-Accrued taxes	(142		)	1,456			352
-Retail fuel cost over recovery	(212		)	(231		)	289
-Mirror CWIP	—			—			(271		)
-Other current liabilities	(45		)	250			58
Net cash provided from operating activities	6,395			4,894			6,274
Investing Activities:
Business acquisitions, net of cash acquired	(1,070		)	(10,689		)	(1,719		)
Property additions	(7,423		)	(7,310		)	(5,674		)
Proceeds pursuant to the Toshiba Guarantee, net of joint owner portion	1,682			—			—
Investment in restricted cash	(17		)	(733		)	(160		)
Distribution of restricted cash	34			742			154
Nuclear decommissioning trust fund purchases	(811		)	(1,160		)	(1,424		)
Nuclear decommissioning trust fund sales	805			1,154			1,418
Cost of removal, net of salvage	(313		)	(245		)	(167		)
Change in construction payables, net	259			(121		)	402
Investment in unconsolidated subsidiaries	(152		)	(1,444		)	—
Payments pursuant to LTSAs	(227		)	(134		)	(197		)
Other investing activities	42			(108		)	87
Net cash used for investing activities	(7,191		)	(20,048		)	(7,280		)
Financing Activities:
Increase (decrease) in notes payable, net	(401		)	1,228			73
Proceeds —
Long-term debt	5,858			16,368			7,029
Common stock	793			3,758			256
Preferred stock	250			—			—
Short-term borrowings	1,259			—			755
Redemptions and repurchases —
Long-term debt	(2,930		)	(3,145		)	(3,604		)
Common stock	—			—			(115		)
Interest-bearing refundable deposits	—			—			(275		)
Preferred and preference stock	(658		)	—			(412		)
Short-term borrowings	(659		)	(478		)	(255		)
Distributions to noncontrolling interests	(119		)	(72		)	(18		)
Capital contributions from noncontrolling interests	80			682			341
Payment of common stock dividends	(2,300		)	(2,104		)	(1,959		)
Other financing activities	(222		)	(512		)	(116		)
Net cash provided from financing activities	951			15,725			1,700
Net Change in Cash and Cash Equivalents	155			571			694
Cash and Cash Equivalents at Beginning of Year	1,975			1,404			710
Cash and Cash Equivalents at End of Year	$	2,130		$	1,975		$	1,404

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents Index to Financial Statements

CONSOLIDATED BALANCE SHEETS

At December 31, 2017 and 2016

Southern Company and Subsidiary Companies 2017 Annual Report



Assets	2017			2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	2,130		$	1,975
Receivables —
Customer accounts receivable	1,806			1,583
Energy marketing receivable	607			623
Unbilled revenues	810			706
Under recovered fuel clause revenues	171			—
Income taxes receivable, current	63			544
Other accounts and notes receivable	635			377
Accumulated provision for uncollectible accounts	(44		)	(43		)
Materials and supplies	1,438			1,462
Fossil fuel for generation	594			689
Natural gas for sale	595			631
Prepaid expenses	452			364
Other regulatory assets, current	604			581
Other current assets	211			230
Total current assets	10,072			9,722
Property, Plant, and Equipment:
In service	103,542			98,416
Less: Accumulated depreciation	31,457			29,852
Plant in service, net of depreciation	72,085			68,564
Nuclear fuel, at amortized cost	883			905
Construction work in progress	6,904			8,977
Total property, plant, and equipment	79,872			78,446
Other Property and Investments:
Goodwill	6,268			6,251
Equity investments in unconsolidated subsidiaries	1,513			1,549
Other intangible assets, net of amortization of $186 and $62 at December 31, 2017 and December 31, 2016, respectively	873			970
Nuclear decommissioning trusts, at fair value	1,832			1,606
Leveraged leases	775			774
Miscellaneous property and investments	249			270
Total other property and investments	11,510			11,420
Deferred Charges and Other Assets:
Deferred charges related to income taxes	825			1,629
Unamortized loss on reacquired debt	206			223
Other regulatory assets, deferred	6,943			6,851
Other deferred charges and assets	1,577			1,406
Total deferred charges and other assets	9,551			10,109
Total Assets	$	111,005		$	109,697

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents Index to Financial Statements

CONSOLIDATED BALANCE SHEETS

At December 31, 2017 and 2016

Southern Company and Subsidiary Companies 2017 Annual Report



Liabilities and Stockholders' Equity	2017		2016
	(in millions)
Current Liabilities:
Securities due within one year	$	3,892	$	2,587
Notes payable	2,439		2,241
Energy marketing trade payables	546		597
Accounts payable	2,530		2,228
Customer deposits	542		558
Accrued taxes —
Accrued income taxes	6		193
Unrecognized tax benefits	18		385
Other accrued taxes	613		667
Accrued interest	488		518
Accrued compensation	959		915
Asset retirement obligations, current	351		378
Acquisitions payable	5		489
Other regulatory liabilities, current	337		236
Other current liabilities	868		925
Total current liabilities	13,594		12,917
Long-Term Debt (See accompanying statements)	44,462		42,629
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	6,842		14,092
Deferred credits related to income taxes	7,256		219
Accumulated deferred ITCs	2,267		2,228
Employee benefit obligations	2,256		2,299
Asset retirement obligations, deferred	4,473		4,136
Accrued environmental remediation	389		397
Other cost of removal obligations	2,684		2,748
Other regulatory liabilities, deferred	239		258
Other deferred credits and liabilities	691		880
Total deferred credits and other liabilities	27,097		27,257
Total Liabilities	85,153		82,803
Redeemable Preferred Stock of Subsidiaries (See accompanying statements)	324		118
Redeemable Noncontrolling Interests (See accompanying statements)	—		164
Total Stockholders' Equity (See accompanying statements)	25,528		26,612
Total Liabilities and Stockholders' Equity	$	111,005	$	109,697
Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents Index to Financial Statements

CONSOLIDATED STATEMENTS OF CAPITALIZATION

At December 31, 2017 and 2016

Southern Company and Subsidiary Companies 2017 Annual Report



		2017			2016			2017		2016
		(in millions)						(percent of total)
Long-Term Debt:
Long-term debt payable to affiliated trusts —
Variable rate (4.44% at 12/31/17) due 2042		$	206		$	206
Long-term senior notes and debt —
Maturity	Interest Rates
2017	1.30% to 7.20%	—			2,019
2018	1.50% to 5.40%	2,402			2,403
2019	1.85% to 5.55%	3,074			3,076
2020	2.00% to 4.75%	2,273			1,326
2021	2.35% to 9.10%	2,643			2,655
2022	1.00% to 8.70%	2,016			1,378
2023 through 2047	1.85% to 7.30%	22,142			20,369
Variable rates (1.82% to 3.75% at 1/1/17) due 2017		—			461
Variable rates (2.29% to 3.05% at 12/31/17) due 2018		1,420			1,520
Variable rates (2.04% to 2.18% at 12/31/17) due 2020		825			—
Variable rates (2.55% to 2.79% at 12/31/17) due 2021		25			25
Variable rate (3.75% at 1/1/17) due 2032 to 2036		—			15
Total long-term senior notes and debt		36,820			35,247
Other long-term debt —
Pollution control revenue bonds —
Maturity	Interest Rates
2019	4.55%	25			25
2022	2.10% to 2.35%	90			90
2023 through 2049	1.15% to 5.15%	1,379			1,339
Variable rates (2.45% to 2.50% at 12/31/17) due 2018		40			76
Variable rates (1.86% to 1.87% at 12/31/17) due 2021		65			65
Variable rates (1.83% to 1.84% at 12/31/17) due 2022		17			17
Variable rates (1.59% to 1.88% at 12/31/17) due 2024 to 2053		1,680			1,721
Plant Daniel revenue bonds (7.13%) due 2021		270			270
FFB loans —
2.57% to 3.86% due 2020		44			44
2.57% to 3.86% due 2021		44			44
2.57% to 3.86% due 2022		44			44
2.57% to 3.86% due 2023 to 2044		2,493			2,493
First mortgage bonds —
4.70% due 2019		50			50
2.66% to 6.58% due 2023 to 2057		975			575
Gas facility revenue bonds —
Variable rate (1.71% at 12/31/17) due 2022		47			47
Variable rate (1.71% at 12/31/17) due 2024 to 2033		154			154
Junior subordinated notes (5.00% to 6.25%) due 2057 to 2077		3,570			2,350
Total other long-term debt		10,987			9,404
Unamortized fair value adjustment of long-term debt		525			578
Capitalized lease obligations		204			136
Unamortized debt premium		44			52
Unamortized debt discount		(206		)	(194		)
Unamortized debt issuance expense		(226		)	(213		)
Total long-term debt (annual interest requirement — $1.8 billion)		48,354			45,216
Less amount due within one year		3,892			2,587
Long-term debt excluding amount due within one year		44,462			42,629			63.2	%	61.3	%

Table of Contents Index to Financial Statements



CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 2017 and 2016 Southern Company and Subsidiary Companies 2017 Annual Report
	2017			2016			2017		2016
	(in millions)						(percent of total)
Redeemable Preferred Stock of Subsidiaries:
Cumulative preferred stock
$100 par or stated value — 4.20% to 5.44%
Authorized — 20 million shares
Outstanding — 1 million shares	324			81
$1 par value — 5.83%
Authorized — 28 million shares
Outstanding — 2017: no shares
— 2016: 2 million shares: $25 stated value	—			37
Total redeemable preferred stock of subsidiaries (annual dividend requirement — $16 million)	324			118			0.5		0.2
Redeemable Noncontrolling Interests	—			164			—		0.2
Common Stockholders' Equity:
Common stock, par value $5 per share —	5,038			4,952
Authorized — 1.5 billion shares
Issued — 2017: 1.0 billion shares
— 2016: 991 million shares
Treasury — 2017: 0.9 million shares
— 2016: 0.8 million shares
Paid-in capital	10,469			9,661
Treasury, at cost	(36		)	(31		)
Retained earnings	8,885			10,356
Accumulated other comprehensive loss	(189		)	(180		)
Total common stockholders' equity	24,167			24,758			34.4		35.6
Preferred and Preference Stock of Subsidiaries and Noncontrolling Interests:
Non-cumulative preferred stock
$25 par value — 6.00% to 6.13%
Authorized — 60 million shares
Outstanding — 2017: no shares
— 2016: 2 million shares	—			45
Non-cumulative preference stock
$1 par value — 6.45% to 6.50%
Authorized — 65 million shares
Outstanding — 2017: no shares	—			196
— 2016: 8 million shares
$100 par or stated value — 5.60% to 6.50%
Outstanding — 2017: no shares	—			368
— 2016: 4 million shares
Noncontrolling interests	1,361			1,245
Total preferred and preference stock of subsidiaries and noncontrolling interests	1,361			1,854			1.9		2.7
Total stockholders' equity	25,528			26,612
Total Capitalization	$	70,314		$	69,523		100.0	%	100.0	%

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents Index to Financial Statements

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

For the Years Ended December 31, 2017, 2016, and 2015

Southern Company and Subsidiary Companies 2017 Annual Report



	Southern Company Common Stockholders' Equity
	Number of Common Shares			Common Stock											Accumulated Other Comprehensive Income (Loss)			Preferred and Preference Stock of Subsidiaries			Noncontrolling Interests
	Issued	Treasury		Par Value		Paid-In Capital			Treasury			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Preferred and Preference Stock of Subsidiaries			Noncontrolling Interests			Total
	(in thousands)			(in millions)
Balance at December 31, 2014	908,502	(725	)	$	4,539	$	5,955		$	(26	)	$	9,609		$	(128	)	$	756		$	221		$	20,926
Consolidated net income attributable to Southern Company	—	—		—		—			—			2,367			—			—			—			2,367
Other comprehensive income (loss)	—	—		—		—			—			—			(2		)	—			—			(2		)
Stock issued	6,571	(2,599	)	33		223			—			—			—			—			—			256
Stock-based compensation	—	—		—		100			—			—			—			—			—			100
Stock repurchased, at cost	—	—		—		—			(115		)	—			—			—			—			(115		)
Cash dividends of $2.1525 per share	—	—		—		—			—			(1,959		)	—			—			—			(1,959		)
Preference stock redemption	—	—		—		—			—			—			—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—		—			—			—			—			—			567			567
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(18		)	(18		)
Net loss attributable to noncontrolling interests	—	—		—		—			—			—			—			—			12			12
Other	—	(28	)	—		4			(1		)	(7		)	—			3			(1		)	(2		)
Balance at December 31, 2015	915,073	(3,352	)	4,572		6,282			(142		)	10,010			(130		)	609			781			21,982
Consolidated net income attributable to Southern Company	—	—		—		—			—			2,448			—			—			—			2,448
Other comprehensive income (loss)	—	—		—		—			—			—			(50		)	—			—			(50		)
Stock issued	76,140	2,599		380		3,263			115			—			—			—			—			3,758
Stock-based compensation	—	—		—		120			—			—			—			—			—			120
Cash dividends of $2.2225 per share	—	—		—		—			—			(2,104		)	—			—			—			(2,104		)
Contributions from noncontrolling interests	—	—		—		—			—			—			—			—			618			618
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(57		)	(57		)
Purchase of membership interests from noncontrolling interests	—	—		—		—			—			—			—			—			(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—		—			—			—			—			—			32			32
Other	—	(66	)	—		(4		)	(4		)	2			—			—			—			(6		)
Balance at December 31, 2016	991,213	(819	)	4,952		9,661			(31		)	10,356			(180		)	609			1,245			26,612
Consolidated net income attributable to Southern Company	—	—		—		—			—			842			—			—			—			842
Other comprehensive income (loss)	—	—		—		—			—			—			(9		)	—			—			(9		)
Stock issued	17,319	—		86		707			—			—			—			—			—			793
Stock-based compensation	—	—		—		105			—			—			—			—			—			105
Cash dividends of $2.3000 per share	—	—		—		—			—			(2,300		)	—			—			—			(2,300		)
Preferred and preference stock redemptions	—	—		—		—			—			—			—			(609		)	—			(609		)
Contributions from noncontrolling interests	—	—		—		—			—			—			—			—			79			79
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(122		)	(122		)
Net income attributable to noncontrolling interests	—	—		—		—			—			—			—			—			44			44
Reclassification from redeemable noncontrolling interests	—	—		—		—			—			—			—			—			114			114
Other	—	(110	)	—		(4		)	(5		)	(13		)	—			—			1			(21		)
Balance at December 31, 2017	1,008,532	(929	)	$	5,038	$	10,469		$	(36	)	$	8,885		$	(189	)	$	—		$	1,361		$	25,528

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents Index to Financial Statements

NOTES TO FINANCIAL STATEMENTS

Southern Company and Subsidiary Companies 2017 Annual Report

Index to the Notes to Financial Statements

Table of Contents Index to Financial Statements

NOTES (continued)

Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

The Southern Company (Southern Company or the Company) is the parent company of four traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, ~~Settlement Agreement~~and Mississippi Power – are vertically integrated utilities providing electric service in four 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 the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants and is managing construction of Plant Vogtle Units 3 and 4. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. See Note 12 under "Southern Company Gas – Proposed Sale of Elizabethtown Gas and Elkton Gas" for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities.

The financial statements reflect Southern Company's investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation.

The traditional electric operating companies, Southern Power, certain subsidiaries of Southern Company Gas, and certain other subsidiaries are subject to regulation by the FERC, and the traditional electric operating companies and natural gas distribution utilities are also subject to regulation by their respective state PSCs or other applicable state regulatory agencies. As such, the consolidated financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by relevant state PSCs or other applicable state regulatory agencies. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on Southern Company's results of operations, financial position, or cash flows.

Recently Issued Accounting Standards

Revenue

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

Table of Contents Index to Financial Statements

NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Leases

Other

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. Southern Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.

Table of Contents Index to Financial Statements

NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

December 15, 2019, with early adoption permitted. Southern Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements.

On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. Southern Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.

Regulatory Assets and Liabilities

Table of Contents Index to Financial Statements

NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:



	2017			2016			Note
	(in millions)
Retiree benefit plans	$	3,931		$	3,959		(a,n)
Asset retirement obligations-asset	1,133			1,080			(b,n)
Deferred income tax charges	814			1,590			(b,p)
Environmental remediation-asset	511			491			(j,n)
Property damage reserves-asset	333			206			(i)
Under recovered regulatory clause revenues	317			273			(g)
Remaining net book value of retired assets	306			351			(o)
Loss on reacquired debt	223			243			(c)
Vacation pay	183			182			(f,n)
Long-term debt fair value adjustment	138			155			(d)
Deferred PPA charges	119			141			(e,n)
Kemper County energy facility	88			201			(h)
Other regulatory assets	511			487			(k)
Deferred income tax credits	(7,261		)	(219		)	(b,p)
Other cost of removal obligations	(2,684		)	(2,774		)	(b)
Over recovered regulatory clause revenues	(155		)	(203		)	(g)
Property damage reserves-liability	(135		)	(177		)	(l)
Other regulatory liabilities	(266		)	(120		)	(m)
Total regulatory assets (liabilities), net	$	(1,894	)	$	5,866

Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:


(a)	Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.


(b)	Asset retirement and other cost of removal obligations are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 80 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.


(c)	Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years.


(d)	Recovered over the remaining life of the original debt issuances, which range up to 21 years. For additional information see Note 12 under "Southern Company – Merger with Southern Company Gas."


(e)	Recovered over the life of the PPA for periods up to six years.


(f)	Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.


(g)	Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs or other applicable regulatory agencies over periods generally not exceeding 10 years.


(h)	Includes $114 million of regulatory assets and $26 million of regulatory liabilities to be recovered over periods of eight and six years, respectively. For additional information, see Note 3 under "Kemper County Energy Facility – Rate Recovery – Kemper Settlement Agreement."

(i)


(j)	Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed.


(k)	Comprised of numerous immaterial components including nuclear outage, fuel-hedging losses, deferred income tax charges - Medicare subsidy, cancelled construction projects, building and generating plant leases, property tax, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSCs over periods generally not exceeding 50 years.


(l)	Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs.


(m)	Comprised of numerous immaterial components including retiree benefit plans, fuel-hedging gains, AROs, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs or other applicable regulatory agencies generally over periods not exceeding 20 years.


(n)	Not earning a return as offset in rate base by a corresponding asset or liability.


(o)	Amortized as approved by the appropriate state PSCs over periods generally up to 48 years.


(p)	As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization. The recovery and amortization of these amounts will be determined by the appropriate state PSCs or other applicable regulatory agencies. See Note 3 under "Regulatory Matters" and Note 5 for additional information.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Revenues

Fuel Costs

Cost of Natural Gas

Income and Other Taxes

Federal ITCs and ~~record a regulatory asset that~~PTCs, as well as state ITCs and other state tax credits available to reduce income taxes payable, were not fully utilized in 2017 and will be carried forward and utilized in future years. In addition, Southern Company is expected to have a consolidated federal net operating loss (NOL) carryforward for the 2017 tax year along with various state NOL carryforwards, which would result in income tax benefits in the future, if utilized. See Note 5 under "Current and Deferred Income Taxes – Tax Credit Carryforwards" and " – Net Operating Loss" for additional information.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Property, Plant, and Equipment

The Southern Company system's property, plant, and equipment in service consisted of the following at December 31:



	2017		2016
	(in millions)
Electric utilities:
Generation	$	51,279	$	48,836
Transmission	11,562		11,156
Distribution	19,239		18,418
General	4,276		4,629
Plant acquisition adjustment	126		126
Electric utility plant in service	86,482		83,165
Natural gas distribution utilities:
Transportation and distribution	13,078		11,996
Utility plant in service	99,560		95,161
Information technology equipment and software	752		544
Communications equipment	456		424
Storage facilities	1,598		1,463
Other	1,176		824
Total other plant in service	3,982		3,255
Total plant in service	$	103,542	$	98,416

Assets acquired under a capital lease are included ~~as an offset~~in property, plant, and equipment and are further detailed in the table below:



	Asset Balances at December 31,
	2017			2016
	(in millions)
Office buildings	$	216		$	61
Nitrogen plant^(*)	—			83
Computer-related equipment	51			63
Gas pipeline	6			6
Less: Accumulated amortization	(72		)	(69		)
Balance, net of amortization	$	201		$	144


(*)	Represents a nitrogen supply agreement for the air separation unit of the Kemper County energy facility, which was terminated following the suspension of the gasifier portion of the project. See Note 6 under "Capital Leases" for additional information.

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Southern Company and Subsidiary Companies 2017 Annual Report

Depreciation and Amortization

Under the terms of the 2013 ARP, Georgia Power amortized approximately $14 million annually from 2014 through 2016 of its remaining regulatory liability related to other cost of removal obligations.

Asset Retirement Obligations and Other Costs of Removal

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Southern Company and Subsidiary Companies 2017 Annual Report

Details of the AROs included in the balance sheets are as follows:



	2017			2016
	(in millions)
Balance at beginning of year	$	4,514		$	3,759
Liabilities incurred	16			66
Liabilities settled	(177		)	(171		)
Accretion	179			162
Cash flow revisions	292			698
Balance at end of year	$	4,824		$	4,514

Nuclear Decommissioning

The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the IRS. While Alabama Power and Georgia Power are allowed to prescribe an ~~aggregate~~overall investment policy to the Funds' managers, neither Southern Company nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of Southern Company, Alabama Power, and Georgia Power. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.

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Southern Company and Subsidiary Companies 2017 Annual Report

At December 31, 2017 and 2016, the accumulated provisions for the external decommissioning trust funds were as follows:



	External Trust Funds
	2017		2016
	(in millions)
Plant Farley	$	902	$	790
Plant Hatch	583		511
Plant Vogtle Units 1 and 2	346		303



	Plant Farley		Plant Hatch		Plant Vogtle Units 1 and 2
Decommissioning periods:
Beginning year	2037		2034		2047
Completion year	2076		2075		2079
	(in millions)
Site study costs:
Radiated structures	$	1,362	$	678	$	568
Spent fuel management	—		160		147
Non-radiated structures	80		64		89
Total site study costs	$	1,442	$	902	$	804

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Allowance for Funds Used During Construction and Interest Capitalized

Impairment of Long-Lived Assets

Goodwill and Other Intangible Assets and Liabilities

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Southern Company and Subsidiary Companies 2017 Annual Report

At December 31, 2017 and 2016, other intangible assets were as follows:



		At December 31, 2017							At December 31, 2016
	Estimated Useful Life	Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net
		(in millions)							(in millions)
Other intangible assets subject to amortization:
Customer relationships	11-26 years	$	288	$	(83	)	$	205	$	268	$	(32	)	$	236
Trade names	5-28 years	159		(17		)	142		158		(5		)	153
Storage and transportation contracts	1-5 years	64		(34		)	30		64		(2		)	62
PPA fair value adjustments	10-20 years	456		(47		)	409		456		(22		)	434
Other	1-12 years	17		(5		)	12		11		(1		)	10
Total other intangible assets subject to amortization		$	984	$	(186	)	$	798	$	957	$	(62	)	$	895
Other intangible assets not subject to amortization:
Federal Communications Commission licenses		75		—			75		75		—			75
Total other intangible assets		$	1,059	$	(186	)	$	873	$	1,032	$	(62	)	$	970

Amortization associated with other intangible assets in 2017, 2016, and 2015 totaled $124 million, $50 million, and $3 million, respectively.

As of December 31, 2017, the estimated amortization associated with other intangible assets for the next five years is as follows:



	Amortization
	(in millions)
2018	$	95
2019	77
2020	65
2021	56
2022	51



	Amortization
	(in millions)
2018	$	24
2019	17

Storm Damage Reserves

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Southern Company and Subsidiary Companies 2017 Annual Report

"Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information regarding Alabama Power's NDR and Georgia Power's deferred storm costs, respectively.

Leveraged Leases

Southern Company's net investment in domestic and international leveraged leases consists of the following at December 31:



	2017			2016
	(in millions)
Net rentals receivable	$	1,498		$	1,481
Unearned income	(723		)	(707		)
Investment in leveraged leases	775			774
Deferred taxes from leveraged leases	(252		)	(309		)
Net investment in leveraged leases	$	523		$	465

A summary of the components of income from the leveraged leases follows:



	2017			2016			2015
	(in millions)
Pretax leveraged lease income	$	25		$	25		$	20
Net impact of Tax Reform Legislation	48			—			—
Income tax expense	(9		)	(9		)	(7		)
Net leveraged lease income	$	64		$	16		$	13

Cash and Cash Equivalents

For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.

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Southern Company and Subsidiary Companies 2017 Annual Report

Materials and Supplies

Fuel Inventory

Natural Gas for Sale

The natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a weighted average cost of gas (WACOG) basis.

Financial Instruments

Comprehensive Income

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Southern Company and Subsidiary Companies 2017 Annual Report

Accumulated OCI (loss) balances, net of tax effects, were as follows:



	Qualifying Hedges			Pension and Other Postretirement Benefit Plans			Accumulated Other Comprehensive Income (Loss)
	(in millions)
Balance at December 31, 2016	$	(115	)	$	(65	)	$	(180	)
Current period change	(4		)	(5		)	(9		)
Balance at December 31, 2017	$	(119	)	$	(70	)	$	(189	)

2. RETIREMENT BENEFITS

Actuarial Assumptions



Assumptions used to determine net periodic costs:	2017		2016		2015
Pension plans
Discount rate – benefit obligations	4.40	%	4.58	%	4.17	%
Discount rate – interest costs	3.77		3.88		4.17
Discount rate – service costs	4.81		4.98		4.48
Expected long-term return on plan assets	7.92		8.16		8.20
Annual salary increase	4.37		4.37		3.59
Other postretirement benefit plans
Discount rate – benefit obligations	4.23	%	4.38	%	4.04	%
Discount rate – interest costs	3.54		3.66		4.04
Discount rate – service costs	4.64		4.85		4.39
Expected long-term return on plan assets	6.84		6.66		6.97
Annual salary increase	4.37		4.37		3.59

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report



Assumptions used to determine benefit obligations:	2017		2016
Pension plans
Discount rate	3.80	%	4.40	%
Annual salary increase	4.32		4.37
Other postretirement benefit plans
Discount rate	3.68	%	4.23	%
Annual salary increase	4.32		4.37



	Initial Cost Trend Rate		Ultimate Cost Trend Rate		Year That Ultimate Rate is Reached
Pre-65	6.50	%	4.50	%	2026
Post-65 medical	5.00		4.50		2026
Post-65 prescription	10.00		4.50		2026

An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2017 as follows:



	1 Percent Increase		1 Percent Decrease
	(in millions)
Benefit obligation	$	132	$	113
Service and interest costs	4		3

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Southern Company and Subsidiary Companies 2017 Annual Report

Pension Plans



	2017			2016
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	12,385		$	10,542
Acquisitions	—			1,244
Service cost	293			262
Interest cost	455			422
Benefits paid	(596		)	(466		)
Plan amendments	(26		)	39
Actuarial (gain) loss	1,297			342
Balance at end of year	13,808			12,385
Change in plan assets
Fair value of plan assets at beginning of year	11,583			9,234
Acquisitions	—			837
Actual return (loss) on plan assets	1,953			902
Employer contributions	52			1,076
Benefits paid	(596		)	(466		)
Fair value of plan assets at end of year	12,992			11,583
Accrued liability	$	(816	)	$	(802	)

Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following:



	2017			2016
	(in millions)
Other regulatory assets, deferred	$	3,273		$	3,207
Other current liabilities	(53		)	(53		)
Employee benefit obligations	(763		)	(749		)
Other regulatory liabilities, deferred	(118		)	(87		)
Accumulated OCI	107			100

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Southern Company and Subsidiary Companies 2017 Annual Report



	Prior Service Cost		Net (Gain) Loss
	(in millions)
Balance at December 31, 2017:
Accumulated OCI	$	3	$	104
Regulatory assets	14		3,140
Total	$	17	$	3,244
Balance at December 31, 2016:
Accumulated OCI	$	4	$	96
Regulatory assets	51		3,069
Total	$	55	$	3,165
Estimated amortization in net periodic pension cost in 2018:
Accumulated OCI	$	1	$	9
Regulatory assets	4		204
Total	$	5	$	213



	Accumulated OCI			Regulatory Assets
	(in millions)
Balance at December 31, 2015	$	125		$	2,998
Net (gain) loss	(20		)	243
Change in prior service costs	2			37
Reclassification adjustments:
Amortization of prior service costs	(1		)	(13		)
Amortization of net gain (loss)	(6		)	(145		)
Total reclassification adjustments	(7		)	(158		)
Total change	(25		)	122
Balance at December 31, 2016	$	100		$	3,120
Net (gain) loss	15			227
Change in prior service costs	—			(26		)
Reclassification adjustments:
Amortization of prior service costs	(1		)	(11		)
Amortization of net gain (loss)	(7		)	(155		)
Total reclassification adjustments	(8		)	(166		)
Total change	7			35
Balance at December 31, 2017	$	107		$	3,155

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Components of net periodic pension cost were as follows:



	2017			2016			2015
	(in millions)
Service cost	$	293		$	262		$	257
Interest cost	455			422			445
Expected return on plan assets	(897		)	(782		)	(724		)
Recognized net (gain) loss	162			150			215
Net amortization	12			14			25
Net periodic pension cost	$	25		$	66		$	218



	Benefit Payments
	(in millions)
2018	$	634
2019	637
2020	663
2021	681
2022	704
2023 to 2027	3,836

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Other Postretirement Benefits

Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows:



	2017			2016
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	2,297		$	1,989
Acquisitions	—			338
Service cost	24			22
Interest cost	79			76
Benefits paid	(136		)	(119		)
Actuarial (gain) loss	65			(16		)
Plan amendments	3			—
Retiree drug subsidy	7			7
Balance at end of year	2,339			2,297
Change in plan assets
Fair value of plan assets at beginning of year	944			833
Acquisitions	—			100
Actual return (loss) on plan assets	154			58
Employer contributions	84			65
Benefits paid	(129		)	(112		)
Fair value of plan assets at end of year	1,053			944
Accrued liability	$	(1,286	)	$	(1,353	)

Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following:



	2017			2016
	(in millions)
Other regulatory assets, deferred	$	382		$	419
Other current liabilities	(5		)	(4		)
Employee benefit obligations	(1,281		)	(1,349		)
Other regulatory liabilities, deferred	(41		)	(41		)
Accumulated OCI	4			7

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report



	Prior Service Cost		Net (Gain) Loss
	(in millions)
Balance at December 31, 2017:
Accumulated OCI	$	—	$	4
Net regulatory assets	21		320
Total	$	21	$	324
Balance at December 31, 2016:
Accumulated OCI	$	—	$	7
Net regulatory assets	25		353
Total	$	25	$	360
Estimated amortization as net periodic postretirement benefit cost in 2018:
Net regulatory assets	$	7	$	14



	Accumulated OCI			Net Regulatory Assets (Liabilities)
	(in millions)
Balance at December 31, 2015	$	8		$	411
Net (gain) loss	(1		)	(13		)
Reclassification adjustments:
Amortization of prior service costs	—			(6		)
Amortization of net gain (loss)	—			(14		)
Total reclassification adjustments	—			(20		)
Total change	(1		)	(33		)
Balance at December 31, 2016	$	7		$	378
Net (gain) loss	(3		)	(21		)
Change in prior service costs	—			3
Reclassification adjustments:
Amortization of prior service costs	—			(6		)
Amortization of net gain (loss)	—			(13		)
Total reclassification adjustments	—			(19		)
Total change	(3		)	(37		)
Balance at December 31, 2017	$	4		$	341

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Components of the other postretirement benefit plans' net periodic cost were as follows:



	2017			2016			2015
	(in millions)
Service cost	$	24		$	22		$	23
Interest cost	79			76			78
Expected return on plan assets	(66		)	(60		)	(58		)
Net amortization	20			21			21
Net periodic postretirement benefit cost	$	57		$	59		$	64



	Benefit Payments		Subsidy Receipts			Total
	(in millions)
2018	$	144	$	(7	)	$	137
2019	148		(8		)	140
2020	151		(8		)	143
2021	154		(9		)	145
2022	156		(9		)	147
2023 to 2027	780		(48		)	732

Benefit Plan Assets

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Southern Company and Subsidiary Companies 2017 Annual Report

Investment Strategies and Benefit Plan Asset Fair Values

A description of the major asset classes that the pension and other postretirement benefit plans are comprised of, along with the valuation methods used for fair value measurement, is provided below:



Description	Valuation Methodology
● Domestic equity: A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. ● International equity: A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.	Domestic and International equities such as common stocks, American depositary receipts, and real estate investment trusts that trade on public exchanges are classified as Level 1 investments and are valued at the closing price in the active market. Equity funds with unpublished prices are valued as Level 2 when the underlying holdings are comprised of Level 1 or Level 2 equity securities.
● Fixed income: A mix of domestic and international bonds.	Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
● Trust-owned life insurance (TOLI): Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio.	Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate accounts. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.
● Special situations: Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as investments in promising new strategies of a longer-term nature. ● Real estate: Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. ● Private equity: Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.	Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

These fair values exclude cash, receivables related to investment income and pending investment sales, and payables related to pending investment purchases.



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient				Target Allocation		Actual Allocation
As of December 31, 2017:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Domestic equity^(*)	$	2,405	$	1,159	$	—	$	—	$	3,564	26	%	31	%
International equity^(*)	1,555		1,403		—		—		2,958		25		25
Fixed income:											23		24
U.S. Treasury, government, and agency bonds	—		841		—		—		841
Mortgage- and asset-backed securities	—		8		—		—		8
Corporate bonds	—		1,201		—		—		1,201
Pooled funds	—		650		—		—		650
Cash equivalents and other	217		11		—		—		228
Real estate investments	469		—		—		1,188		1,657		14		13
Special situations	—		—		—		180		180		3		1
Private equity	—		—		—		669		669		9		6
Total	$	4,646	$	5,273	$	—	$	2,037	$	11,956	100	%	100	%


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient				Target Allocation		Actual Allocation
As of December 31, 2016:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Domestic equity^(*)	$	2,010	$	927	$	—	$	—	$	2,937	26	%	29	%
International equity^(*)	1,231		1,110		—		—		2,341		25		22
Fixed income:											23		29
U.S. Treasury, government, and agency bonds	—		588		—		—		588
Mortgage- and asset-backed securities	—		13		—		—		13
Corporate bonds	—		991		—		—		991
Pooled funds	—		524		—		—		524
Cash equivalents and other	996		2		—		—		998
Real estate investments	310		—		—		1,152		1,462		14		13
Special situations	—		—				180		180		3		2
Private equity	—		—		—		549		549		9		5
Total	$	4,547	$	4,155	$	—	$	1,881	$	10,583	100	%	100	%


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient
As of December 31, 2017:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Domestic equity^(*)	$	155	$	323	$	—	$	—	$	478
International equity^(*)	—		166		—		—		166
Fixed income:
U.S. Treasury, government, and agency bonds	—		85		—		—		85
Corporate bonds	—		39		—		—		39
Cash equivalents and other	84		25		—		48		157
Real estate investments	3		—		—		16		19
Private equity	—		—		—		1		1
Total	$	242	$	638	$	—	$	65	$	945


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient
As of December 31, 2016:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Domestic equity^(*)	$	142	$	343	$	—	$	—	$	485
International equity^(*)	—		185		—		—		185
Fixed income:
U.S. Treasury, government, and agency bonds	—		85		—		—		85
Corporate bonds	—		41		—		—		41
Pooled funds	—		66		—		—		66
Cash equivalents and other	12		5		—		83		100
Real estate investments	4		—		—		15		19
Private equity	—		—		—		2		2
Total	$	158	$	725	$	—	$	100	$	983


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

The composition of Southern Company Gas' pension plan assets as of December 31, 2017 and 2016, along with the targets, is presented below:



	Target		2017		2016
Pension plan assets:
Equity	53	%	65	%	69	%
Fixed Income	15		19		20
Cash	2		6		1
Other	30		10		10
Balance at end of period	100	%	100	%	100	%

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient		Total		Target Allocation		Actual Allocation
As of December 31, 2017:	(Level 1)		(Level 2)		(Level 3)		(NAV)
	(in millions)
Assets:
Domestic equity^(*)	$	132	$	35	$	—	$	—	$	167	37	%	40	%
International equity^(*)	47		76		—		—		123		23		23
Fixed income:											30		29
U.S. Treasury, government, and agency bonds	—		32		—		—		32
Corporate bonds	—		37		—		—		37
Pooled funds	—		55		—		—		55
Cash equivalents and other	10		—		—		—		10
Trust-owned life insurance	—		426		—		—		426
Real estate investments	16		—		—		36		52		5		5
Special situations	—		—		—		5		5		1		1
Private equity	—		—		—		20		20		4		2
Total	$	205	$	661	$	—	$	61	$	927	100	%	100	%


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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Southern Company and Subsidiary Companies 2017 Annual Report



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient				Target Allocation		Actual Allocation
As of December 31, 2016:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Domestic equity^(*)	$	118	$	28	$	—	$	—	$	146	39	%	40	%
International equity^(*)	37		61		—		—		98		23		21
Fixed income:											29		31
U.S. Treasury, government, and agency bonds	—		24		—		—		24
Corporate bonds	—		30		—		—		30
Pooled funds	—		49		—		—		49
Cash equivalents and other	41		—		—		—		41
Trust-owned life insurance	—		382		—		—		382
Real estate investments	11		—		—		35		46		5		5
Special situations	—		—		—		5		5		1		1
Private equity	—		—		—		17		17		3		2
Total	$	207	$	574	$	—	$	57	$	838	100	%	100	%


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient		Total
As of December 31, 2017:	(Level 1)		(Level 2)		(Level 3)		(NAV)
	(in millions)
Assets:
Domestic equity^(*)	$	3	$	69	$	—	$	—	$	72
International equity^(*)	—		22		—		—		22
Fixed income:
Pooled funds	—		24		—		—		24
Cash equivalents and other	2		—		—		1		3
Total	$	5	$	115	$	—	$	1	$	121


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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Southern Company and Subsidiary Companies 2017 Annual Report



	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient		Total
As of December 31, 2016:	(Level 1)		(Level 2)		(Level 3)		(NAV)
	(in millions)
Assets:
Domestic equity^(*)	$	3	$	58	$	—	$	—	$	61
International equity^(*)	—		18		—		—		18
Fixed income:
Pooled funds	—		23		—		—		23
Cash equivalents and other	1		—		—		2		3
Total	$	4	$	99	$	—	$	2	$	105


(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

The composition of Southern Company Gas' other postretirement benefit plan assets as of December 31, 2017 and 2016, along with the targets, is presented below:



	Target		2017		2016
Other postretirement benefit plan assets:
Equity	72	%	76	%	74	%
Fixed Income	24		20		23
Cash	1		2		1
Other	3		2		2
Total	100	%	100	%	100	%

Employee Savings Plan

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

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Southern Company and its subsidiaries are subject to certain claims 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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, water, land, and protection of other natural resources, 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 against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements.

Environmental Matters

Environmental Remediation

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Nuclear Fuel Disposal Costs

On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant.

FERC Matters

Market-Based Rate Authority

The traditional electric operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power filed a request for rehearing and filed their response with the FERC in 2015.

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The ultimate outcome of these matters cannot be determined at this time.

Regulatory Matters

Alabama Power

Rate RSE

Rate CNP PPA

Alabama Power's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 7, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2017 through March 31, 2018. No adjustment to Rate CNP PPA is expected in 2018. As of December 31, 2017 and 2016, Alabama Power had an under recovered Rate CNP PPA balance of $12 million and $142 million, respectively, which is included in deferred under recovered regulatory clause revenues in the balance sheet.

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Rate CNP Compliance

Rate CNP Compliance allows for the recovery of Alabama Power's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.

On December 5, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2018 the factors associated with Alabama Power's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered amounts associated with 2018 will be reflected in the 2019 filing. As of December 31, 2017 and 2016, Alabama Power had a deferred under recovered regulatory clause revenues balance of $17 million and $9 million, respectively.

Rate ECR

Alabama Power has established energy cost recovery rates under Alabama Power's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on Southern Company's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH.

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance in Rate ECR to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2017.

On December 5, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2018 the energy cost recovery rates which began in 2017. Therefore, the Rate ECR factor as of January 1, 2018 remained at 2.015 cents per KWH. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC.

At December 31, 2017, Alabama Power's under recovered fuel costs totaled $25 million, which is included in other regulatory assets, current. At December 31, 2016, Alabama Power had an over recovered fuel balance of $76 million, which was included in other regulatory liabilities, current. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery or return of fuel costs.

Rate NDR

Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. When the reserve balance falls below $50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both

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components is $10 per month per non-residential customer account and $5 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. No such accruals were recorded or designated in any period presented.

In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million. Alabama Power expects to collect approximately $16 million annually until the reserve balance is restored to $75 million. The NDR balance at December 31, 2017 was $38 million.

As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.

Environmental Accounting Order

Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. The regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance.

Alabama Power retired Plant Gorgas Units 6 and 7 (200 MWs) and Plant Barry Unit 3 (225 MWs) in 2015. Additionally, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs) in 2015, but such units remain available on a limited basis with natural gas as the fuel source. In April 2016, Alabama Power also ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively.

In accordance with this accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to regulatory assets at their respective retirement dates. These regulatory assets are being amortized and recovered through Rate CNP Compliance over the units' remaining useful lives, as established prior to the decision for retirement; therefore, these decisions associated with coal operations had no significant impact on Southern Company's financial statements.

Georgia Power

Rate Plans

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC in April 2016, the 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60/40 basis with their respective customers; thereafter, all merger savings will be retained by customers.

In accordance with the 2013 ARP, the Georgia PSC approved increases to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately $49 million; (2) Environmental Compliance Cost Recovery tariff by approximately $75 million; (3) Demand-Side Management tariffs by approximately $3 million; and (4) Municipal Franchise Fee tariff by approximately $13 million, for a total increase in base revenues of approximately $140 million. There were no changes to these tariffs in 2017.

Under the 2013 ARP, Georgia Power's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2015, Georgia Power's retail ROE was within the allowed retail ROE range. In 2016, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power will refund to retail customers approximately $44 million in 2018, as approved by the Georgia PSC on January 16, 2018. In 2017, Georgia Power's retail ROE was within the allowed retail ROE range, subject to review and approval by the Georgia PSC.

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On January 19, 2018, the Georgia PSC issued an order on the Tax Reform Legislation, which was amended on February 16, 2018 (Tax Order). In accordance with the Tax Order, Georgia Power is required to submit its analysis of the Tax Reform Legislation and related recommendations to address the related impacts on Georgia Power's cost of service and annual revenue requirements by March 6, 2018. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plan

Fuel Cost Recovery

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. In 2015, the Georgia PSC approved Georgia Power's request to lower annual billings by approximately $350 million effective January 1, 2016. In May 2016, the Georgia PSC approved Georgia Power's request to further lower annual billings under an interim fuel rider by approximately $313 million effective June 1, 2016, which expired on December 31, 2017. The Georgia PSC will review Georgia Power's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case unless Georgia Power deems it necessary to file a fuel case at an earlier time. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under recovered fuel balance exceeds $200 million.

Georgia Power's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48-month time horizon.

Georgia Power's under recovered fuel balance totaled $165 million at December 31, 2017 and is included in current assets. At December 31, 2016, Georgia Power's over recovered fuel balance totaled $84 million and is included in other regulatory liabilities, current.

Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow.

Storm Damage Recovery

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October 2016, respectively. The incremental restoration costs related to these hurricanes deferred in Georgia Power's regulatory asset for storm damage totaled approximately $260 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements.

At December 31, 2017 and December 31, 2016, the total balance in Georgia Power's regulatory asset related to storm damage was $333 million and $206 million, respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $303 million and $176 million included in other regulatory assets, deferred, respectively.

Gulf Power

Retail Base Rate Cases

In 2013, the Florida PSC approved a settlement agreement related to Gulf Power's 2013 retail base rate case that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million ~~between~~from January 2014 ~~and~~through June 2017. In any given month, such depreciation ~~expense~~ reduction ~~may~~was not to exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. ~~Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in Gulf Power's next base rate case or next depreciation~~For 2014 and ~~dismantlement study proceeding, whichever comes first. For~~ 2015, ~~and 2014,~~ Gulf Power recognized reductions in depreciation ~~expense~~ of $8.4 million and $20.1 million, ~~and $8.4 million,~~ respectively.

~~Pursuant to the~~ No net reduction in depreciation was recorded in 2016. In 2017, Gulf Power recognized the remaining $34.0 million reduction in depreciation.

On April 4, 2017, the Florida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three intervenors with respect to Gulf Power's request in 2016 to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power ~~may not request~~increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes. Gulf Power also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause.

The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to Gulf Power's base rates. Under the terms of the 2017 Rate Case Settlement Agreement, by March 1, 2018, Gulf Power must identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to Gulf Power's base rates and $15.6 million to Gulf Power's environmental cost recovery rates effective beginning the first calendar month following approval.

The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through Gulf Power's fuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and Gulf Power will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.

The ultimate outcome of these matters cannot be determined at this time.

Mississippi Power

On February 7, 2018, Mississippi Power revised its annual projected Performance Evaluation Plan (PEP) filing for 2018 to reflect the impacts of the Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a

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performance adjusted ROE of 9.33% and an increased equity ratio of 55%. The ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. Atlanta Gas Light earns revenue for its ~~retail~~distribution services by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically.

With the exception of Atlanta Gas Light, 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 and energy efficiency plans. See Note 1 under "Cost of Natural Gas" for additional information.

Regulatory Infrastructure Programs

Certain of Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs are 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. Initial program lengths range from nine to 10 years, with completion dates ranging from 2020 through 2025.

On February 21, 2017, the Georgia PSC approved a rate adjustment mechanism for Atlanta Gas Light that included the 2017 capital investment associated with a four-year extension of one of its existing infrastructure programs, with a total additional investment of $177 million through 2020.

Base Rate Cases

The Illinois Commerce Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commerce Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which Nicor Gas expects to file by the end of the second quarter 2018.

The ultimate outcome of these matters cannot be ~~effective until after June 2017, unless Gulf Power's actual retail ROE falls below the authorized ROE range.~~determined at this time.

~~Integrated Coal Gasification Combined Cycle~~

Kemper ~~IGCC~~ County Energy Facility

Overview

~~Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service.~~ The Kemper ~~IGCC will~~County energy facility was designed to utilize an IGCC technology with an expected output capacity of 582 ~~MWs. The Kemper IGCC will~~MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper ~~IGCC.~~County energy facility. The mine, operated by North American Coal Corporation, started

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commercial operation in 2013. In connection with the Kemper ~~IGCC,~~County energy facility construction, Mississippi Power constructed ~~and plans to operate~~ approximately 61 miles of CO₂ pipeline infrastructure for the ~~planned~~ transport of captured CO₂ for use in enhanced oil recovery.

~~Kemper IGCC~~ Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, ~~a detailed order~~ confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper ~~IGCC.~~County energy facility. The certificated cost estimate of the Kemper ~~IGCC~~County energy facility included in the 2012 MPSC CPCN Order was ~~$2.4~~$2.4 billion,, net of ~~$245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and excluding~~approximately $0.57 billion for the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and ~~AFUDC related to the Kemper IGCC.~~certain general exceptions (Cost Cap Exceptions). The 2012 MPSC CPCN Order approved a construction cost cap of up to ~~$2.88~~$2.88 billion,, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper ~~IGCC~~County energy facility was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper ~~IGCC~~County energy facility in service ~~using~~in August 2014.

The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO₂, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas ~~in August 2014~~price forecast had decreased significantly and ~~currently expects~~the estimated cost of operating and maintaining the facility during the first five full years of operations had increased significantly since certification.

On June 21, 2017, the Mississippi PSC stated its intent to ~~place~~issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the ~~remainder~~Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of the related costs (Kemper Settlement Docket). On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper ~~IGCC,~~County energy facility, given the uncertainty as to its future. On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement).

At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including ~~the gasifier and the gas clean-up facilities, in service during the third quarter 2016.~~

~~Recovery~~approximately $5.95 billion of ~~the~~ costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE for the Kemper County energy facility. In the aggregate, Mississippi Power had recorded charges to income of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017.

Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and ~~equipment,~~gasifier-related costs, and certain termination costs during the ~~cost~~suspension period prior to conclusion of the CO₂ ~~pipeline facilities, AFUDC,~~Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below. Additional pre-tax cancellation costs, including mine and ~~certain general exceptions, including change of law, force majeure,~~plant closure and ~~beneficial capital (which exists when~~contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power ~~demonstrates that~~has begun efforts to dispose of or abandon the ~~purpose~~mine and ~~effect~~gasifier-related assets.

Rate Recovery

Kemper Settlement Agreement

On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement. The Kemper Settlement Agreement provides for an annual revenue requirement of ~~the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative~~approximately $99.3 million for costs related to the ~~original proposal~~Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the ~~CPCN) (Cost Cap Exceptions) remains subject to review~~related regulatory assets and ~~approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts~~liabilities of ~~the Mississippi Supreme Court's (Court) decision),~~eight years and ~~actual costs incurred as of December 31, 2015, are as follows:~~six years, respectively. The revenue requirement also

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Cost Category
2010
Project Estimate^(f)

Current Cost Estimate^(a)
Actual Costs
(in billions)
Plant Subject to Cost Cap^(b)(g)
$ 2.40
$ 5.29
$ 4.83
Lignite Mine and Equipment 0.21 0.23 0.23
CO₂ Pipeline Facilities
0.14 0.11 0.11
AFUDC^(c)
0.17 0.69 0.59
Combined Cycle and Related Assets Placed in
Service – Incremental^(d)(g)
—
0.01 0.01
General Exceptions 0.05 0.10 0.09
Deferred Costs^(e)(g)
—
0.20 0.17
Total Kemper IGCC $ 2.97
$ 6.63
$ 6.03


~~(a)~~	~~Amounts~~reflects a disallowance related to a portion of Mississippi Power's investment in ~~the Current Cost Estimate reflect estimated costs through August 31, 2016.~~

~~(b)~~

The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information.


~~(c)~~	Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction.


~~(d)~~	Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information.


~~(e)~~	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein.


~~(f)~~	~~The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO~~₂ ~~pipeline facilities which was approved in 2011 by the Mississippi PSC.~~


~~(g)~~	Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with assets placed in service and other non-CWIP accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2015.

Of the ~~total costs, including post-in-service costs~~Kemper County energy facility requested for inclusion in rate base, which was recorded in the ~~lignite mine, incurred~~fourth quarter 2017 as an additional charge to income of ~~December 31, 2015, $3.47 billion was included in property, plant, and equipment (which is~~approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).

Under the ~~DOE Grants~~Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and estimated probable losses of $2.41 billion), $2 million in other property and investments, $69 million in fossil fuel stock, $45 million in materials and supplies, $21 million in other regulatory assets, current, $195 million in other regulatory assets, deferred, and $11 million in other deferred charges and assets in the balance sheet.

~~Mississippi Power does not intend to seek rate~~include no recovery for ~~any~~ costs ~~related to~~associated with the ~~construction~~gasifier portion of the Kemper ~~IGCC that exceed~~County energy facility in 2018 or at any future date. On February 12, 2018, Mississippi Power made the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Southern Company recorded pre-tax charges to income for revisions to the cost estimate above the cost cap of $365 million ($226 million after tax), $868 million ($536 million after tax), and $1.2 billion ($729 million after tax) in 2015, 2014, and 2013, respectively. The increases to the cost estimate in 2015 primarily reflect costs for the extension of the Kemper IGCC's projected in-service date through August 31, 2016, increased efforts related to scope modifications, additional labor costs in support of start-up and operational readiness activities, and system repairs and modifications after startup testing and commissioning activities identified necessary remediation of equipment installation, fabrication, and design issues, including the refractory lining inside the gasifiers; the lignite feed and dryer systems; and the syngas cooler vessels. Any extension of the in-service date beyond August 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service datecompliance filing with ~~respect to the Kemper IGCC beyond August 31, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by~~ the Mississippi PSC. ~~These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on~~The Kemper ~~IGCC assets placed in service and consulting and legal fees of approximately $2 million per month. For additional information, see "2015 Rate Case" herein.~~

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~~Mississippi Power's analysis of~~Settlement Agreement also requires (i) the ~~time needed to complete the start-up and commissioning activities~~CPCN for the Kemper ~~IGCC will continue until the remaining Kemper IGCC assets are placed in service. Further cost increases and/or extensions of the in-service date with respect~~County energy facility to ~~the Kemper IGCC may result from factors including, but not limited~~be modified to ~~labor costs~~limit it to natural gas combined cycle operation and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material.

~~Rate Recovery of Kemper IGCC Costs~~

The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on the Company's results of operations, financial condition, and liquidity.

~~2012 MPSC CPCN Order~~

The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN.(ii) Mississippi Power ~~expects the Mississippi PSC~~ to apply operational parameters in connection with future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could befile a ~~material adverse impact on the financial statements.~~

~~2013 MPSC Rate Order~~

~~In January 2013, Mississippi Power entered into a settlement agreement~~reserve margin plan with the Mississippi PSC ~~that was intended to establish~~by August 2018.

As of December 31, 2017, the ~~process for resolving matters regarding cost recovery related to~~balances associated with the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC,County energy facility regulatory assets and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013liabilities were $114 million and ~~3% effective January 1, 2014, which collectively were designed to collect $156~~$26 million, ~~annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service.~~

Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts.

On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation discussed below.

~~2015 Rate Case~~respectively.

As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.

2015 ~~Court decision, on July 10,~~Rate Case

On December 3, 2015, ~~Mississippi Power filed a supplemental filing including a request for interim rates (Supplemental Notice) with~~ the Mississippi PSC ~~which presented an alternative rate proposal (In-Service Asset Proposal) for consideration by~~issued the ~~Mississippi PSC. The~~ In-Service Asset ~~Proposal was based upon the test period of June 2015 to May 2016, was designed to recover Mississippi Power's costs associated with~~Rate Order regarding the Kemper ~~IGCC~~County energy facility assets that ~~are~~were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and

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water pipeline) and other related costs, and was designed to collect approximately $159 million annually. On August 13, 2015, the Mississippi PSC approved the implementation of interim rates that became effective with the first billing cycle in September, subject to refund and certain other conditions.

On December 3, 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order) adopting in full a stipulation (the 2015 Stipulation) entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal. Consistent with the 2015 Stipulation, thecosts. The In-Service Asset Rate Order ~~provides~~provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest ~~costs during the test period.~~costs. The In-Service Asset Rate Order also ~~includes~~included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. ~~The stipulated revenue requirement excludes~~

In connection with the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. See "Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

~~With~~ implementation of the new rate on December 17, 2015, the interim rates were terminated and Mississippi Power recorded a customer refund of approximately $11 million in December 2015 for the difference between the interim rates collected and the permanent rates. The refund is required to be completed by March 16, 2016.

Pursuant to the In-Service Asset Rate Order, Mississippi Power is required to file a subsequent rate request within 18 months. As part of the filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.

~~On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a notice of appeal~~ of the In-Service Asset Rate Order with the Court. Mississippi Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of operations. The ultimate outcome of this matter cannot be determined at this time.

~~Legislation to authorize a multi-year rate plan~~ and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power expects to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact Mississippi Power's ability to utilize alternate financing through securitization or the February 2013 legislation.

Mississippi Power expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at December 31, 2015 of $6.63 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

~~Regulatory Assets and Liabilities~~

Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015, in connection with the implementation of interimwholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs ~~(associated with assets placed in service and other non-CWIP accounts)~~ that previously were deferred ~~as regulatory assets~~ and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal ~~fees. The amortization~~fees over periods ~~for these regulatory assets vary~~ranging from two years to 10 ~~years as set forth in~~years. On July 6, 2017, the ~~In-Service Asset Rate Order. As of December 31, 2015,~~Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the ~~balance associated with these regulatory assets was $120 million. Other regulatory assets associated with~~Kemper County energy facility following the ~~remainder~~July 2017 completion of the ~~Kemper IGCC totaled $96 million as of December 31, 2015. The~~

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amortization period for certain of these ~~assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.~~

~~See "2013 MPSC Rate Order" herein for information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP.~~

The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. As of December 31, 2015, Mississippi Power recorded a related regulatory ~~liability of approximately $2 million. See "2015 Rate Case" herein for additional information.~~assets.

Lignite Mine and CO₂ Pipeline Facilities

~~In conjunction with the Kemper IGCC,~~ Mississippi Power ~~will own~~owns the lignite mine and equipment and ~~has acquired and will continue to acquire~~ mineral reserves located around the Kemper ~~IGCC~~County energy facility site. The mine started commercial operation in June 2013.

In 2010, Mississippi Power executed a 40~~-year~~40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is ~~operating and managing~~responsible for the mining ~~operations. The contract with Liberty Fuels is effective~~operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. Mississippi Power expects mine reclamation to begin in 2018. In addition to the obligation to fund the reclamation activities, Mississippi Power ~~currently provides~~provided working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.

In addition, Mississippi Power ~~has~~ constructed ~~and will operate~~ the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil ~~recovery. Mississippi Power has~~recovery and entered into ~~agreements~~an agreement with Denbury Onshore (Denbury)~~, a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant~~ to ~~which Denbury will~~ purchase ~~70% of~~ the CO₂ ~~captured from the Kemper IGCC and Treetop will purchase 30% of the CO~~₂ ~~captured from the Kemper IGCC. The agreements with Denbury and Treetop provide Denbury and Treetop with termination rights as Mississippi Power has not satisfied its contractual obligation to deliver~~ captured CO₂ ~~by May 11, 2015. Since May 11, 2015,~~. Denbury has the right to terminate the contract at any time because Mississippi Power ~~has been engaged~~did not place the Kemper IGCC in ~~ongoing discussions with its off-takers regarding the status of the CO~~₂ ~~delivery schedule as well as other issues related to the CO~~₂ agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their agreement that do not affect pricing or minimum purchase quantities. Potential requirements imposed on CO₂ off-takers under the Clean Power Plan (if ultimately enacted in its current form, pending resolution of litigation) and the potential adverse financial impact of low oil prices on the off-takers increase the risk that the CO₂ contracts may be terminated or materially modified. Any termination or material modification of these agreements is not expected to have a material impact on Southern Company's revenues. Additionally, if the contracts remain in place, sustained oil price reductions could result in significantly lower revenues than Mississippi Power forecasted to be available to offset customer rate impacts.service by July 1, 2017.

The ultimate outcome of these matters cannot be determined at this time.

~~Termination of Proposed Sale of Undivided Interest~~Litigation

~~In 2010 and~~include, among other things, Southern Company as ~~amended in 2012,~~a defendant. The individual plaintiff alleges that Mississippi Power and ~~SMEPA entered into an agreement whereby SMEPA agreed to purchase a 15% undivided interest in~~Southern Company violated the ~~Kemper IGCC. On May 20, 2015, SMEPA notified~~Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power that it was terminating the agreement. Mississippi Power had previously received a total of $275 million of deposits from SMEPA that were returned to SMEPA, with interest of approximately $26 million, on June 3, 2015, as a result of the termination byand Southern Company ~~pursuant~~concealed, falsely represented, and failed to ~~its guarantee obligation. Subsequently, Mississippi Power issued a promissory note in~~fully disclose important facts concerning the ~~aggregate principal amount of approximately $301 million to Southern Company, which matures December 1, 2017.~~

~~The In-Service Asset Proposal~~cost and the related rates approved by the Mississippi PSC excluded any costs associated with the 15% undivided interest. Mississippi Power continues to evaluate its alternatives with respect to its investment and the related costs associated with the 15% undivided interest.

~~Bonus Depreciation~~

On December 18, 2015, the Protecting Americans from Tax Hikes (PATH) Act was signed into law. Bonus depreciation was extended for qualified property placed in service over the next five years. The PATH Act allows for 50% bonus depreciation for 2015, 2016, and 2017; 40% bonus depreciation for 2018; and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. The extension of 50% bonus depreciation is expected to result in approximately $3 million of positive cash flows related to the combined cycle and associated common facilities portionschedule of the Kemper ~~IGCC for~~County energy facility and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the ~~2015 tax year~~Circuit Court to appoint a receiver to oversee, operate, manage, and ~~approximately $360 million for~~otherwise control all affairs relating to the ~~2016 tax year, which may not all be realized in 2016 due~~Kemper County energy facility; ask the Circuit Court to ~~a projected NOL on the~~

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revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company intends to vigorously defend itself in this matter and the ultimate outcome of this matter cannot be determined at this time.

On June 9, 2016, ~~income tax return,~~Treetop, Greenleaf CO₂ Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint related to the cancelled CO₂ contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and sought compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO₂ contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages. On December 28, 2017, Mississippi Power reached a settlement agreement with Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group and the arbitration was dismissed.

Nuclear Construction

Project Status

In 2009, the Georgia PSC certified construction of 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. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

Georgia Power expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. Georgia Power's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under the Guarantee Settlement Agreement and the Customer Refunds, each as defined herein). Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.

Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy

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Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of December 31, 2017.

On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share was approximately $1.7 billion. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, Georgia Power, the other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of Georgia Power, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and Georgia Power and the other Vogtle Owners surrendered the Westinghouse Letters of Credit.

On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, 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 (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power 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 because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. 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.

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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 nuclear construction projects certified by the Georgia PSC. 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. As of December 31, 2017, Georgia Power had recovered approximately $1.6 billion of financing costs. On January 30, 2018, Georgia Power filed to decrease the NCCR tariff by approximately $50 million, effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, refunds to customers ordered by the Georgia PSC aggregating approximately $188 million (Customer Refunds), and the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and will be paid in three installments of $25 to each retail customer no later than the third quarter 2018.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. Georgia Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of operations, financial condition, and liquidity.

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The ultimate outcome of these matters cannot be determined at this time.

Cost and Schedule



	(in billions)
Project capital cost forecast	$	7.3
Net investment as of December 31, 2017	(3.4		)
Remaining estimate to complete	$	3.9

Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.

The ultimate outcome of these matters cannot be determined at this time.

Other Matters

As of December 31, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

The ultimate outcome of these matters cannot be determined at this time.

Other Matters

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Southern Company and Subsidiary Companies 2017 Annual Report

Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At December 31, 2017, the facility's property, plant, and equipment had a net book value of $112 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.

The cavern continues to maintain its pressures and overall structural integrity. These events were considered in connection with Southern Company Gas' annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the ~~remainder~~cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the ~~Kemper IGCC in service in 2016. See "Kemper IGCC Schedule and Cost Estimate" herein for additional information.~~cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this ~~time.~~time, but could have a significant impact on Southern Company's financial statements.

~~Investment Tax Credits~~

~~The IRS allocated~~ ~~$279 million~~ (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. These tax credits were dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO₂ ~~produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. As a result of the schedule extension for the Kemper IGCC, the Phase II tax credits have been recaptured.~~

~~Section 174 Research and Experimental Deduction~~

Southern Company reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013, 2014, and 2015. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $423 million as of December 31, 2015. See "Bonus Depreciation" herein and Note 5 under "Unrecognized Tax Benefits" for additional information. The ultimate outcome of this matter cannot be determined at this time.

4. JOINT OWNERSHIP AGREEMENTS

Alabama Power owns an undivided interest in Units 1 and 2 at Plant Miller and related facilities jointly with PowerSouth Energy Cooperative, Inc. Georgia Power owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: ~~OPC,~~Oglethorpe Power Corporation (OPC), MEAG Power, the City of Dalton, Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities, Florida Power & Light Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain ~~facilities and with Duke Energy Florida, Inc. for a~~facilities. In August 2016, Georgia Power sold its 33% ownership interest in the Intercession City combustion turbine unit ~~at Intercession City, Florida. Subsequent to December 31, 2015, Georgia Power exercised its contractual option to sell its ownership interest~~ to Duke Energy Florida, ~~Inc. contingent on regulatory approvals.~~LLC. Southern Power owns an undivided interest in Plant Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency. Southern Company Gas has a 50% undivided ownership interest in the Dalton Pipeline jointly with The Williams Companies, Inc.

At December 31, ~~2015~~2017, Alabama Power's, Georgia Power's, Southern Power's, and Southern ~~Power's~~Company Gas' percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows:


Facility (Type)	Percent Ownership		Plant in Service		Accumulated Depreciation		CWIP		Percent Ownership		Plant in Service		Accumulated Depreciation		CWIP
			(in millions)								(in millions)
Plant Vogtle (nuclear) Units 1 and 2	45.7	%	$	3,503	$	2,084	$	63	45.7	%	$	3,564	$	2,141	$	70
Plant Hatch (nuclear)	50.1		1,230		568		90		50.1		1,321		595		87
Plant Miller (coal) Units 1 and 2	91.8		1,518		587		63		91.8		1,717		619		54
Plant Scherer (coal) Units 1 and 2	8.4		260		86		1		8.4		261		93		8
Plant Wansley (coal)	53.5		915		290		13		53.5		1,053		335		72
Rocky Mountain (pumped storage)	25.4		181		125		—		25.4		182		132		—
Intercession City (combustion turbine)	33.3		13		4		—
Plant Stanton (combined cycle) Unit A	65.0		157		53		—		65.0		155		55		—
Dalton Pipeline (natural gas pipeline)									50.0		241		2		13

Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4, ~~that~~which are currently under ~~construction.~~construction and had a CWIP balance of $3.3 billion as of December 31, 2017. See Note 3 under ~~"Retail Regulatory Matters – Georgia Power –~~ "Nuclear ~~Construction"~~Construction" for additional information.

Alabama Power and Georgia Power have contracted to operate and maintain their jointly-owned facilities, except for Rocky Mountain, ~~and Intercession City,~~ as agents for their respective co-owners. Southern Power has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton Unit A. The companies' proportionate share of their plant operating expenses is included in the corresponding operating expenses in the statements of income and each company is responsible for providing its own financing.

~~II-97~~Southern Company Gas entered into an agreement to lease its 50% undivided ownership in the Dalton Pipeline that became effective when it was placed in service on August 1, 2017. Under the lease, Southern Company Gas will receive approximately $26 million annually for an initial term of 25 years. The lessee is responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff.

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Southern Company and Subsidiary Companies ~~2015~~2017 Annual Report

5. INCOME TAXES

Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. PowerSecure and Southern Company Gas became participants in the income tax allocation agreement as of May 9, 2016 and July 1, 2016, respectively. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.

Federal Tax Reform Legislation

Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, Southern Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Southern Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note 3 under "Regulatory Matters" for additional information.

Current and Deferred Income Taxes

Details of income tax provisions are as follows:


	2015			2014		2013			2017			2016			2015
	(in millions)								(in millions)
Federal —
Current	$	(177	)	$	175	$	363		$	(62	)	$	1,184		$	(177	)
Deferred	1,266			695		386			(6		)	(342		)	1,266
	1,089			870		749			(68		)	842			1,089
State —
Current	(33		)	93		(10		)	37			(108		)	(33		)
Deferred	138			14		110			173			217			138
	105			107		100			210			109			105
Total	$	1,194		$	977	$	849		$	142		$	951		$	1,194

~~1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES~~

~~General~~5. INCOME TAXES

Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. PowerSecure and Southern Company Gas became participants in the income tax allocation agreement as of May 9, 2016 and July 1, 2016, respectively. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.

Federal Tax Reform Legislation

Current and Deferred Income Taxes

Details of income tax provisions are as follows:



	2017			2016			2015
	(in millions)
Federal —
Current	$	(62	)	$	1,184		$	(177	)
Deferred	(6		)	(342		)	1,266
	(68		)	842			1,089
State —
Current	37			(108		)	(33		)
Deferred	173			217			138
	210			109			105
Total	$	142		$	951		$	1,194

Net cash payments (refunds) for income taxes in 2017, 2016, and 2015 were $(410) million, $(148) million, and $(9) million, respectively.

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Southern Company and Subsidiary Companies 2017 Annual Report

The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:



	2017			2016
	(in millions)
Deferred tax liabilities —
Accelerated depreciation	$	10,267		$	15,392
Property basis differences	955			2,708
Leveraged lease basis differences	251			314
Employee benefit obligations	516			737
Premium on reacquired debt	54			89
Regulatory assets associated with employee benefit obligations	1,046			1,584
Regulatory assets associated with AROs	1,225			1,781
Other	697			907
Total	15,011			23,512
Deferred tax assets —
Federal effect of state deferred taxes	326			597
Employee benefit obligations	1,307			1,868
Over recovered fuel clause	—			66
Other property basis differences	446			401
Deferred costs	69			100
ITC carryforward	2,420			1,974
Federal NOL carryforward	518			1,084
Unbilled revenue	57			92
Other comprehensive losses	84			152
AROs	1,197			1,732
Estimated Loss on Kemper IGCC	722			484
Deferred state tax assets	328			266
Regulatory liability associated with the Tax Reform Legislation (not subject to normalization)	465			—
Other	485			679
Total	8,424			9,495
Valuation allowance	(149		)	(23		)
Total deferred income taxes	6,736			14,040
Portion included in accumulated deferred tax assets	(106		)	(52		)
Accumulated deferred income taxes	$	6,842		$	14,092

The implementation of the Tax Reform Legislation significantly reduced accumulated deferred income taxes, partially offset by bonus depreciation provisions in the Protecting Americans from Tax Hikes Act. The Tax Reform Legislation also significantly reduced tax-related regulatory assets and increased tax-related regulatory liabilities.

At December 31, 2017, the tax-related regulatory assets to be recovered from customers were $825 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest.

At December 31, 2017, the tax-related regulatory liabilities to be credited to customers were $7.3 billion. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs.

In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies and the natural gas distribution utilities are amortized over the life of the related property with such amortization normally applied as a credit to

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Southern Company and Subsidiary Companies 2017 Annual Report

reduce depreciation in the statements of income. Credits amortized in this manner amounted to $22 million in 2017, $22 million in 2016, and $21 million in 2015. Southern Power's deferred federal ITCs are amortized to income tax expense over the life of the asset. Credits amortized in this manner amounted to $57 million in 2017, $37 million in 2016, and $19 million in 2015. Also, Southern Power received cash related to federal ITCs under the renewable energy incentives of $162 million for the year ended December 31, 2015. No cash was received related to these incentives in 2017 and 2016. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. The tax benefit of the related basis differences reduced income tax expense by $18 million in 2017, $173 million in 2016, and $54 million in 2015. See "Unrecognized Tax Benefits" below for further information.

Tax Credit Carryforwards

At December 31, 2017, Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) which are expected to result in $2.1 billion of federal income tax benefits. The federal ITC carryforwards begin expiring in 2034 but are expected to be fully utilized by 2027. The PTC carryforwards begin expiring in 2032 but are expected to be fully utilized by 2027. The acquisition of additional renewable projects could further delay existing tax credit carryforwards. The ultimate outcome of these matters cannot be determined at this time.

Additionally, Southern Company had state ITC carryforwards for the state of Georgia totaling approximately $318 million, which will expire between 2020 and 2027 but are expected to be fully utilized.

Net Operating Loss

After carrying back portions of the federal NOL generated in 2016, Southern Company had a consolidated federal NOL carryforward of approximately $2.3 billion at December 31, 2017. The federal NOL will begin expiring in 2037 but is expected to be fully utilized by 2019. The ultimate outcome of this matter cannot be determined at this time.

At December 31, 2017, the state NOL carryforwards for Southern Company's subsidiaries were as follows:



Jurisdiction	Approximate NOL Carryforwards		Approximate Net State Income Tax Benefit		Tax Year NOL Begins Expiring
	(in millions)
Mississippi	$	2,890	$	114	2032
Oklahoma	986		47		2036
Georgia	524		23		2019
New York	229		13		2036
New York City	209		15		2036
Florida	304		13		2034
Other states	465		24		Various
Total	$	5,607	$	249

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Effective Tax Rate

A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:



	2017		2016		2015
Federal statutory rate	35.0	%	35.0	%	35.0	%
State income tax, net of federal deduction	12.5		2.1		1.9
Employee stock plans dividend deduction	(4.1	)	(1.2	)	(1.2	)
Non-deductible book depreciation	3.1		0.9		1.2
AFUDC-Equity	(2.6	)	(2.0	)	(2.2	)
Non-deductible equity portion on Kemper IGCC write-off	15.7		—		—
ITC basis difference	(1.7	)	(5.0	)	(1.5	)
Federal PTCs	(12.1	)	(1.2	)	—
Amortization of ITC	(4.2	)	(0.9	)	(0.5	)
Tax Reform Legislation	(25.6	)	—		—
Other	(2.7	)	(0.4	)	0.2
Effective income tax rate	13.3	%	27.3	%	32.9	%

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 federal income tax benefits from ITCs and PTCs. However, in 2017, the effective tax rate was primarily lower due to the remeasurement of deferred income taxes resulting from the Tax Reform Legislation.

In March 2016, the FASB issued ASU 2016-09, which changed the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on Southern Company's overall effective tax rate. See Note 1 under "Recently Issued Accounting Standards" for additional information.

Legal Entity Reorganization

In September 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization included the purchase of all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $55 million related to certain changes in state apportionment rates and net operating loss carryforward utilization that will be recorded in the first quarter 2018. The ultimate outcome of this matter cannot be determined at this time.

Unrecognized Tax Benefits

Changes during the year in unrecognized tax benefits were as follows:



	2017			2016			2015
	(in millions)
Unrecognized tax benefits at beginning of year	$	484		$	433		$	170
Tax positions increase from current periods	10			45			43
Tax positions increase from prior periods	10			21			240
Tax positions decrease from prior periods	(196		)	(15		)	(20		)
Reductions due to settlements	(290		)	—			—
Balance at end of year	$	18		$	484		$	433

The tax positions increase from current and prior periods for 2017 and 2016 relate primarily to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility, as well as deductions for R&E expenditures associated with the Kemper County energy facility. The tax positions decrease from prior periods for 2017 and 2016, and the reductions due to settlements for 2017, relate primarily to the

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

settlement of R&E expenditures associated with the Kemper County energy facility and federal income tax benefits from deferred ITCs. See Note 3 under "Kemper County Energy Facility" and "Section 174 Research and Experimental Deduction" herein for more information.

The impact on Southern Company's effective tax rate, if recognized, is as follows:



	2017		2016		2015
	(in millions)
Tax positions impacting the effective tax rate	$	18	$	20	$	10
Tax positions not impacting the effective tax rate	—		464		423
Balance of unrecognized tax benefits	$	18	$	484	$	433

The tax positions impacting the effective tax rate primarily relate to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility and Southern Company's estimate of the uncertainty related to the amount of those benefits. The tax positions not impacting the effective tax rate for 2016 and 2015 relate to deductions for R&E expenditures associated with the Kemper County energy facility. See "Section 174 Research and Experimental Deduction" herein for more information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.

Accrued interest for all tax positions other than the Section 174 R&E deductions was immaterial for all years presented.

Southern Company classifies interest on tax uncertainties as interest expense. Southern Company did not accrue any penalties on uncertain tax positions.

It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.

Section 174 Research and Experimental Deduction

Southern Company has reflected deductions for R&E expenditures related to the Kemper County energy facility in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. As a result of this approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest.

6. FINANCING

Securities Due Within One Year

A summary of scheduled maturities of securities due within one year at December 31 was as follows:



	2017			2016
	(in millions)
Senior notes	$	2,354		$	1,995
Other long-term debt	1,420			485
Revenue bonds^(*)	90			76
Capitalized leases	31			32
Unamortized debt issuance expense/discount	(3		)	(1		)
Total	$	3,892		$	2,587


(*)	Includes $50 million in revenue bonds classified as short term at December 31, 2017 that were remarketed in an index rate mode subsequent to December 31, 2017. Also includes $40 million in pollution control revenue bonds classified as short term since they are variable rate demand obligations supported by short-term credit facilities; however, the final maturity dates range from 2020 to 2028.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Maturities through 2022 applicable to total long-term debt are as follows: $3.9 billion in 2018; $3.2 billion in 2019; $3.2 billion in 2020; $3.1 billion in 2021; and $2.2 billion in 2022.

Bank Term Loans

Southern Company and certain of its subsidiaries have entered into various bank term loan agreements. Unless otherwise stated, the proceeds of these loans were used to repay existing indebtedness and for general corporate purposes, including working capital and, for the subsidiaries, their continuous construction programs.

At December 31, 2017, Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company ~~(the Company)~~had outstanding bank term loans totaling $450 million, $45 million, $250 million, $900 million, and $420 million, respectively, of which $1.5 billion are reflected in the statements of capitalization as long-term debt and $600 million are reflected in the balance sheet as notes payable. At December 31, 2016, Southern Company, Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $400 million, $45 million, $100 million, $1.2 billion, and $380 million, respectively, of which $2.0 billion were reflected in the statements of capitalization as long-term debt and $100 million were reflected in the balance sheet as notes payable.

In June 2017, Southern Company entered into two $100 million aggregate principal amount short-term floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR.

In June 2017, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $50 million and $150 million, with maturity dates of December 1, 2017 and May 31, 2018, respectively, and one long-term floating rate bank loan of $100 million, with a maturity date of June 28, 2018, which was amended in August 2017 to extend the maturity date to October 26, 2018. These loans bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank.

In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.

The outstanding bank loans as of December 31, 2017 have covenants that limit debt levels to a percentage of total capitalization. The percentage is 70% for Southern Company and 65% for Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, as defined in the agreements. For purposes of these definitions, debt excludes any long-term debt payable to affiliated trusts and other hybrid securities. Additionally, for Southern Company and Southern Power Company, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power Company to the extent such debt is non-recourse to Southern Power Company and capitalization excludes the capital stock or other equity attributable to such subsidiary. At December 31, 2017, each of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company was in compliance with its debt limits.

DOE Loan Guarantee Borrowings

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into the Loan Guarantee Agreement in 2014, under which the DOE agreed to guarantee the obligations of Georgia Power under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, Georgia Power, and the FFB and a related promissory note (FFB Promissory Note). The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which Georgia Power may make term loan borrowings through the FFB.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to Georgia Power's entry into the Vogtle Services Agreement and the related intellectual property licenses (IP Licenses).

Under the terms of the Loan Guarantee Agreement, upon termination of the Vogtle 3 and 4 Agreement, further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, Georgia Power will not request any advances unless and until certain conditions are satisfied, including (i) receipt of the DOE's approval of the Bechtel Agreement (together with the Vogtle Services Agreement and the IP Licenses, the Replacement EPC Arrangements) and (ii) Georgia Power's entry into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.

Proceeds of advances made under the FFB Credit Facility are used to reimburse Georgia Power for Eligible Project Costs. Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion.

All borrowings under the FFB Credit Facility are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded 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 requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with 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 under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.

At both December 31, 2017 and 2016, Georgia Power had $2.6 billion of borrowings outstanding under the FFB Credit Facility.

Under the 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 Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility 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 bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iv) 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 Facility. 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 Facility. 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 Facility 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. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, 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.

Senior Notes

Southern Company and its subsidiaries issued a total of $4.0 billion of senior notes in 2017. Southern Company issued $0.3 billion and its subsidiaries issued a total of $3.7 billion. The proceeds of Southern Company's issuances were used to repay short-term indebtedness and for other general corporate purposes. Except as described below, the proceeds of Southern Company's subsidiaries' issuances were used to repay long-term indebtedness, to repay short-term indebtedness, and for other general corporate purposes, including the applicable subsidiaries' continuous construction programs. A portion of the proceeds of Gulf Power's senior note issuances was used to redeem all of Gulf Power's outstanding shares of preference stock. See "Redeemable Preferred Stock of Subsidiaries" herein for additional information.

At December 31, 2017 and 2016, Southern Company and its subsidiaries had a total of $35.1 billion and $33.0 billion, respectively, of senior notes outstanding. At December 31, 2017 and 2016, Southern Company had a total of $10.2 billion and $10.3 billion, respectively, of senior notes outstanding. These amounts include senior notes due within one year.

Since Southern Company is a ~~wholly owned~~holding company, the right of Southern Company and, hence, the right of creditors of Southern Company (including holders of Southern Company senior notes) to participate in any distribution of the assets of any subsidiary of Southern Company, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred stockholders of such subsidiary.

Junior Subordinated Notes

At December 31, 2017 and 2016, Southern Company and its subsidiaries had a total of $3.6 billion and $2.4 billion, respectively, of junior subordinated notes outstanding.

In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.

In November 2017, Southern Company issued $450 million aggregate principal amount of Series 2017B 5.25% Junior Subordinated Notes due December 1, 2077. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.

In September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used to redeem all outstanding shares of Georgia Power's preferred and preference stock. See "Redeemable Preferred Stock of Subsidiaries" herein for additional information.

Pollution Control Revenue Bonds

Pollution control revenue bond obligations represent loans to the traditional electric operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. In some cases, the pollution control revenue bond obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of revenue bonds issued by public authorities. The traditional electric operating companies had $3.3 billion of outstanding pollution control revenue bond obligations at December 31, 2017 and 2016, which includes pollution control revenue bonds classified as due within one year. The traditional electric operating companies are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred.

Plant Daniel Revenue Bonds

In 2011, in connection with Mississippi Power's election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, Mississippi Power assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021, issued for the benefit of the lessor. See "Assets Subject to Lien" herein for additional information.

Gas Facility Revenue Bonds

Pivotal Utility Holdings, Inc., a subsidiary of Southern Company Gas (Pivotal Utility Holdings), is party to a series of loan agreements with the ~~parent~~New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued with maturities ranging from 2022 to 2033. These revenue bonds are issued by state

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agencies or counties to investors, and proceeds from each issuance then are loaned to Southern Company Gas. The amount of gas facility revenue bonds outstanding at December 31, 2017 and 2016 was $200 million.

The Elizabethtown Gas asset sale agreement requires that bonds representing $180 million of the total that are currently eligible for redemption at par be redeemed on or prior to consummation of the sale. The ultimate outcome of this matter cannot be determined at this time. See Note 12 under "Southern Company Gas – Proposed Sale of Elizabethtown Gas and Elkton Gas" for additional information.

Other Revenue Bonds

Other revenue bond obligations represent loans to Mississippi Power from a public authority of funds derived from the sale by such authority of revenue bonds issued to finance a portion of the costs of constructing the Kemper County energy facility and related facilities.

Mississippi Power had $50 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 2017 and 2016. Such amounts are reflected in the statements of capitalization as other long-term debt.

First Mortgage Bonds

Nicor Gas, a subsidiary of Southern Company Gas, had $1.0 billion and $625 million of first mortgage bonds outstanding at December 31, 2017 and 2016, respectively. These bonds have been issued with maturities ranging from 2019 to 2057. Substantially all of Nicor Gas' properties are subject to the lien of the indenture securing these first mortgage bonds. See "Assets Subject to Lien" herein for additional information.

On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. On November 1, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.85% Series due August 10, 2047 and $100 million aggregate principal amount of First Mortgage Bonds 4.00% Series due August 10, 2057. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs.

Long-Term Debt Payable to an Affiliated Trust

Alabama Power has formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to Alabama Power through the issuance of junior subordinated notes totaling $206 million outstanding as of December 31, 2017 and 2016, which constitute substantially all of the assets of this trust and are reflected in the balance sheets as long-term debt payable. Alabama Power considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust's payment obligations with respect to these securities. At December 31, 2017 and 2016, trust preferred securities of $200 million were outstanding.

Capital Leases

Assets acquired under capital leases are recorded in the balance sheets as property, plant, and equipment and the related obligations are classified as long-term debt.

In 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper County energy facility, which resulted in a capital lease obligation of $74 million at December 31, 2016. Following the suspension of the Kemper IGCC, Mississippi Power entered into an asset purchase and settlement agreement in December 2017 with the lessor, which terminated the capital lease obligation. See Note 3 under "Kemper County Energy Facility" for additional information.

At December 31, 2017 and 2016, the capitalized lease obligations for Georgia Power's corporate headquarters building were $22 million and $28 million, respectively, with an annual interest rate of 7.9%.

At December 31, 2017 and 2016, a subsidiary of Southern Company had capital lease obligations of approximately $177 million and $29 million, respectively, for an office building and certain computer equipment including desktops, laptops, servers, printers, and storage devices with annual interest rates that range from 1.5% to 4.7%.

Assets Subject to Lien

Each of Southern Company's subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of ~~four~~Southern Company or any of its other subsidiaries.

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Gulf Power has granted one or more liens on certain of its property in connection with the issuance of certain series of pollution control revenue bonds with an aggregate outstanding principal amount of $41 million as of December 31, 2017.

The revenue bonds assumed in conjunction with Mississippi Power's purchase of Plant Daniel Units 3 and 4 are secured by Plant Daniel Units 3 and 4 and certain related personal property. See "Plant Daniel Revenue Bonds" herein for additional information.

On October 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron Products Company (Chevron), to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038, subject to the approval of the Mississippi PSC. The agreements grant Chevron a security interest in the co-generation assets, with a net book value of approximately $93 million, located at Chevron's refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies.

See "DOE Loan Guarantee Borrowings" above for information regarding certain borrowings of Georgia Power that are secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4.

The first mortgage bonds issued by Nicor Gas are secured by substantially all of Nicor Gas' properties. See "First Mortgage Bonds" herein for additional information.

Under the terms of the PPA and the expansion PPA for Southern Power's Mankato project, which was acquired in 2016, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017. See Note 12 under "Southern Power" for additional information.

During 2015, Southern Power indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock solar facility in Pecos County, Texas. Roserock is in a litigation dispute with McCarthy Building Companies, Inc. (McCarthy) regarding damage to certain solar panels during installation. In connection therewith, Roserock is withholding payments of approximately $26 million from McCarthy, and McCarthy has filed mechanic's liens on the Roserock facility for the same amount. Southern Power intends to vigorously pursue its claims against McCarthy and defend against McCarthy's claims, the ultimate outcome of which cannot be determined at this time.

Bank Credit Arrangements

At December 31, 2017, committed credit arrangements with banks were as follows:



	Expires												Executable Term Loans				Expires Within One Year
Company	2018		2019		2020		2022		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)
Southern Company^(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—	$	—	$	—	$	—
Alabama Power	35		—		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	30		25		225		—		280		280		45		—		20		10
Mississippi Power	100		—		—		—		100		100		—		—		—		100
Southern Power Company^(b)	—		—		—		750		750		728		—		—		—		—
Southern Company Gas^(c)	—		—		—		1,900		1,900		1,890		—		—		—		—
Other	30		—		—		—		30		30		20		—		20		10
Southern Company Consolidated	$	195	$	25	$	725	$	7,200	$	8,145	$	8,094	$	65	$	—	$	40	$	155


(a)	Represents the Southern Company parent entity.


(b)	Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $19 million remains unused at December 31, 2017.


(c)	Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

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In May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement with $1.4 billion and $500 million currently allocated to Southern Company Gas Capital and Nicor Gas, respectively, maturing in 2022. Pursuant to the new multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. In September 2017, Alabama Power also amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020. In November 2017, Gulf Power amended $195 million of its multi-year credit arrangements to extend the maturity dates from 2017 and 2018 to 2020 and Mississippi Power amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018.

Most of the bank credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than ¹/4 of 1% for Southern Company, the traditional electric operating companies, Southern Power ~~SCS, SouthernLINC Wireless,~~Company, Southern Company ~~Holdings, Inc. (Southern Holdings)~~Gas, and Nicor Gas. Compensating balances are not legally restricted from withdrawal.

Southern Company's, Southern Company Gas', and Nicor Gas' credit arrangements contain covenants that limit debt levels to 70% of total capitalization, as defined in the agreements, and most of the other subsidiaries' bank credit arrangements contain covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts and, in certain arrangements and other hybrid securities. Additionally, for Southern Company and Southern Power Company, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power Company to the extent such debt is non-recourse to Southern Power Company and capitalization excludes the capital stock or other equity attributable to such subsidiaries. At December 31, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were each in compliance with their respective debt limit covenants.

A portion of the $8.1 billion 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, and Nicor Gas. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of December 31, 2017 was approximately $1.5 billion as compared to $1.9 billion at December 31, 2016. In addition, at December 31, 2017, the traditional electric operating companies had approximately $714 million of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to December 31, 2017, $50 million of these revenue bonds of Mississippi Power which were in a long-term interest rate mode were remarketed in an index rate mode.

Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets.

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Details of short-term borrowings were as follows:



	Short-term Debt at the End of the Period
	Amount Outstanding		Weighted Average Interest Rate
	(in millions)
December 31, 2017:
Commercial paper	$	1,832	1.8	%
Short-term bank debt	607		2.3	%
Total	$	2,439	1.9	%
December 31, 2016:
Commercial paper	$	1,909	1.1	%
Short-term bank debt	123		1.7	%
Total	$	2,032	1.1	%

In addition to the short-term borrowings of Southern Power Company included in the table above, at December 31, 2016, Southern Power Company subsidiaries had credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. The Project Credit Facilities were fully repaid in January 2017 and had total amounts outstanding of $209 million at a weighted average interest rate of 2.1% at December 31, 2016.

Redeemable Preferred Stock of Subsidiaries

At December 31, 2016, each of the traditional electric operating companies had outstanding preferred and/or preference stock. During 2017, Alabama Power and Gulf Power each redeemed all of its outstanding preference stock and Georgia Power redeemed all of its outstanding preferred and preference stock. The preferred stock of Alabama Power and Mississippi Power contains a feature that allows the holders to elect a majority of such subsidiary's board of directors if preferred dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of Alabama Power and Mississippi Power, this preferred stock is presented as "Redeemable Preferred Stock of Subsidiaries" in a manner consistent with temporary equity under applicable accounting standards. The preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power did not contain such a provision. As a result, under applicable accounting standards, the preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power are presented as "Preferred and Preference Stock of Subsidiaries," a separate component of "Stockholders' Equity," on Southern Company's balance sheets, statements of capitalization, and statements of stockholders' equity.

The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company:



	Redeemable Preferred Stock of Subsidiaries
	(in millions)
Balance at December 31, 2014	$	375
Issued	—
Redeemed	(262		)
Issuance costs	5
Balance at December 31, 2015:	118
Issued	—
Redeemed	—
Balance at December 31, 2016:	118
Issued	250
Redeemed	(38		)
Issuance costs	(6		)
Balance at December 31, 2017:	$	324

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Southern Company and Subsidiary Companies 2017 Annual Report

7. COMMITMENTS

Fuel and Purchased Power Agreements

To supply a portion of the fuel requirements of the generating plants, the Southern Company system has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2017, 2016, and 2015, the traditional electric operating companies and Southern Power incurred fuel expense of $4.4 billion, $4.4 billion, and $4.8 billion, respectively, the majority of which was purchased under long-term commitments. Southern Company expects that a substantial amount of the Southern Company system's future fuel needs will continue to be purchased under long-term commitments.

In addition, the Southern Company system has entered into various long-term commitments for the purchase of capacity and electricity, some of which are accounted for as operating leases or have been used by a third party to secure financing. Total capacity expense under PPAs accounted for as operating leases was $235 million, $232 million, and $227 million for 2017, 2016, and 2015, respectively.

Estimated total obligations under these commitments at December 31, 2017 were as follows:



	Operating Leases		Other
	(in millions)
2018	$	247	$	7
2019	250		6
2020	247		4
2021	249		5
2022	252		4
2023 and thereafter	806		38
Total	$	2,051	$	64

Pipeline Charges, Storage Capacity, and Gas Supply

Pipeline charges, storage capacity, and gas supply include charges recoverable through a natural gas cost recovery mechanism, or alternatively, billed to marketers selling retail natural gas, as well as demand charges associated with Southern Company Gas' wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas' gas marketing services of 35 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2017 and valued at $101 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations.

Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2017 were as follows:



	Pipeline Charges, Storage Capacity, and Gas Supply
	(in millions)
2018	$	813
2019	552
2020	416
2021	375
2022	339
2023 and thereafter	2,294
Total	$	4,789

Operating Leases

The Southern Company system has operating lease agreements with various terms and expiration dates. Total rent expense was $176 million, $169 million, and $130 million for 2017, 2016, and 2015, respectively. Southern Company includes any step rents, fixed escalations, and lease concessions in its computation of minimum lease payments.

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Southern Company and Subsidiary Companies 2017 Annual Report

As of December 31, 2017, estimated minimum lease payments under operating leases were as follows:



	Minimum Lease Payments
	Barges & Railcars		Other^(*)		Total
	(in millions)
2018	$	21	$	128	$	149
2019	11		113		124
2020	9		99		108
2021	8		87		95
2022	6		77		83
2023 and thereafter	5		963		968
Total	$	60	$	1,467	$	1,527


(*)	Includes operating leases for cellular tower space, facilities, vehicles, and other equipment.

For the traditional electric operating companies, a majority of the barge and railcar lease expenses are recoverable through fuel cost recovery provisions.

In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain railcar leases with respect to the residual value of the leased property. These leases have terms expiring through 2024 with maximum obligations under these leases of $44 million. At the termination of the leases, the lessee may renew the lease, exercise its purchase option, or the property can be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the leased property would substantially reduce or eliminate the payments under the residual value obligations.

Guarantees

In 2013, Georgia Power entered into an agreement that requires Georgia Power to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years. The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2018. In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million.

As discussed above under "Operating Leases," Alabama Power and Georgia Power have entered into certain residual value guarantees.

8. COMMON STOCK

Stock Issued

During 2017, Southern Company issued approximately 14.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $659 million.

Shares Reserved

At December 31, 2017, a total of 71 million shares were reserved for issuance pursuant to the Southern Investment Plan, employee savings plans, the Outside Directors Stock Plan, the Omnibus Incentive Compensation Plan (which includes stock options and performance share units as discussed below), and an at-the-market program. Of the total 71 million shares reserved, there were 13 million shares of common stock remaining available for awards under the Omnibus Incentive Compensation Plan as of December 31, 2017.

Stock-Based Compensation

Stock-based compensation primarily in the form of performance share units and restricted stock units may be granted through the Omnibus Incentive Compensation Plan to a large segment of Southern Company system employees ranging from line management to executives. In 2015 and 2016, stock-based compensation consisted exclusively of performance share units. Beginning in 2017, stock-based compensation granted to employees includes restricted stock units in addition to performance

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Southern Company and Subsidiary Companies 2017 Annual Report

share units. Prior to 2015, stock-based compensation also included stock options. As of December 31, 2017, there were 5,112 current and former employees participating in the stock option, performance share unit, and restricted stock unit programs.

In conjunction with the Merger, stock-based compensation in the form of Southern Company restricted stock and performance share units was also granted to certain executives of Southern Company Gas through the Southern Company Omnibus Incentive Compensation Plan.

Performance Share Units

Performance share units granted to employees vest at the end of a three-year performance period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors.

Southern Company issues performance share units with performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three-year performance period as compared to a group of industry peers, performance share units with performance goals based on Southern Company's cumulative earnings per share (EPS) over the performance period, and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period.

In 2015 and 2016, the EPS-based and ROE-based awards each represented 25% of the total target grant date fair value of the performance share unit awards granted. The remaining 50% of the total target grant date fair value consisted of TSR-based awards. Beginning in 2017, the total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units.

The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common stock among the industry peers over the performance period. Southern Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement.

The fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three-year performance period initially assuming a 100% payout at the end of the performance period. Employees become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period.

In determining the fair value of the TSR-based awards issued to employees, the expected volatility is based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the awards. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of performance share award units granted:



Year Ended December 31	2017	2016	2015
Expected volatility	15.6%	15.0%	12.9%
Expected term (in years)	3	3	3
Interest rate	1.4%	0.8%	1.0%
Weighted average grant-date fair value	$49.08	$45.06	$46.38

The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017, 2016, and 2015 was $49.21, $48.87, and $47.75, respectively.

Total unvested performance share units outstanding as of December 31, 2016 were 3.2 million. During 2017, 1.2 million performance share units were granted and 1.5 million performance share units were vested or forfeited, resulting in 2.9 million

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Southern Company and Subsidiary Companies 2017 Annual Report

unvested performance share units outstanding at December 31, 2017. The number of shares to be issued for the three-year performance and vesting period ended December 31, 2017 will be determined in the first quarter 2018.

For the years ended December 31, 2017, 2016, and 2015, total compensation cost for performance share units recognized in income was $74 million, $96 million, and $88 million, respectively, with the related tax benefit also recognized in income of $29 million, $37 million, and $34 million, respectively. As of December 31, 2017, $30 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 21 months.

Restricted Stock Units

Beginning in 2017, stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three-year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period.

The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three-year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one-, two-, or three-year period. Employees become immediately vested in the restricted stock units upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility.

The weighted average grant-date fair value of restricted stock units granted during 2017 was $49.25.

During 2017, 0.6 million restricted stock units were granted and 0.1 million restricted stock units were vested or forfeited, resulting in 0.7 million unvested restricted stock units outstanding at December 31, 2017, including previously issued restricted stock units related to other employee retention agreements.

For the year ended December 31, 2017, total compensation cost for restricted stock units recognized in income was $25 million with the related tax benefit also recognized in income of $10 million. As of December 31, 2017, $8 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 13 months.

Stock Options

In 2015, Southern Company discontinued the granting of stock options and all outstanding options have vested. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur no later than November 2024.

Southern Company's activity in the stock option program for 2017 is summarized below:



	Shares Subject to Option	Weighted Average Exercise Price
	(in millions)
Outstanding at December 31, 2016	24.6	$	41.28
Exercised	6.0	40.03
Cancelled	—	39.90
Outstanding and Exercisable at December 31, 2017	18.6	$	41.68

As of December 31, 2017, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately five years and the aggregate intrinsic value for the options outstanding and options exercisable was $119 million.

Total compensation cost for stock option awards and the related tax benefits recognized in income were immaterial for all years presented.

The total intrinsic value of options exercised during the years ended December 31, 2017, 2016, and 2015 was $64 million, $120 million, and $48 million, respectively. The actual tax benefit for the tax deductions from stock option exercises totaled $25 million, $46 million, and $19 million for the years ended December 31, 2017, 2016, and 2015, respectively. Prior to the adoption of ASU 2016-09, the excess tax benefits related to the exercise of stock options were recognized in Southern Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income.

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Southern Company and Subsidiary Companies 2017 Annual Report

Southern Company has a policy of issuing shares to satisfy share option exercises. Cash received from issuances related to option exercises under the share-based payment arrangements for the years ended December 31, 2017, 2016, and 2015 was $239 million, $448 million, and $154 million, respectively.

Southern Company Gas Restricted Stock Awards

At the effective time of the Merger, each outstanding award of existing Southern Company Gas performance share units was converted into an award of Southern Company's restricted stock units. Under the terms of the restricted stock awards, the employees received Southern Company stock when they satisfy the requisite service period by being continuously employed through the original three-year vesting schedule of the award being replaced. Southern Company issued 0.7 million restricted stock units with a grant-date fair value of $53.83, based on the closing stock price of Southern Company common stock on the date of the grant. As a portion of the fair value of the award related to pre-combination service, the grant date fair value was allocated to pre- or post-combination service and accounted for as Merger consideration or compensation cost, respectively. Approximately $13 million of the grant date fair value was allocated to Merger consideration.

For the years ended December 31, 2017 and 2016, total compensation cost for restricted stock units recognized in income was $8 million and $13 million, respectively, and the related tax benefit also recognized in income was $4 million for each year. As of December 31, 2017, $3 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 12 months.

Southern Company Gas Change in Control Awards

Southern Company awarded performance share units to certain Southern Company Gas employees who continued their employment with the Southern Company in lieu of certain change in control benefits the employee was entitled to receive following the Merger (change in control awards). Shares of Southern Company common stock and/or cash equal to the dollar value of the change in control benefit will vest and be issued one-third each year as long as the employee remains in service with Southern Company or its subsidiaries at each vest date. In addition to the change in control benefit, Southern Company common stock could be issued to the employees at the end of a performance period based on achievement of certain Southern Company common stock price metrics, as well performance goals established by the Compensation Committee of the Southern Company Board of Directors (achievement shares).

The change in control benefits are accounted for as a liability award with the fair value equal to the guaranteed dollar value of the change in control benefit. The grant-date fair value of the achievement portion of the award was determined using a Monte Carlo simulation model to estimate the number of achievement shares expected to vest based on the Southern Company common stock price. The expected payout is reevaluated annually with expense recognized to date increased or decreased proportionately based on the expected performance. The compensation expense ultimately recognized for the achievement shares will be based on the actual performance.

For the years ended December 31, 2017 and 2016, total compensation cost for the change in control awards recognized in income was $12 million and $4 million, respectively. The related tax benefit also recognized in income was $6 million for the year ended December 31, 2017 and an immaterial amount for the year ended December 31, 2016. As of December 31, 2017, approximately $8 million of total unrecognized compensation cost related to change in control awards will be recognized over a weighted-average period of approximately 18 months.

Diluted Earnings Per Share

For Southern Company, the only difference in computing basic and diluted EPS is attributable to awards outstanding under the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted EPS were as follows:



	Average Common Stock Shares
	2017	2016	2015
	(in millions)
As reported shares	1,000	951	910
Effect of options and performance share award units	8	7	4
Diluted shares	1,008	958	914

Prior to the adoption of ASU 2016-09 in 2016, the effect of options and performance share award units included the assumed impacts of any excess tax benefits from the exercise of all "in the money" outstanding share based awards. Stock options and

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Southern Company and Subsidiary Companies 2017 Annual Report

performance share award units that were not included in the diluted EPS calculation because they were anti-dilutive were immaterial in all years presented.

Common Stock Dividend Restrictions

The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2017, consolidated retained earnings included $5.3 billion of undistributed retained earnings of the subsidiaries.

9. NUCLEAR INSURANCE

Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies' nuclear power plants. The Act provides funds up to $13.4 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $450 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. A company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests in all licensed reactors, is $255 million and $247 million, respectively, per incident, but not more than an aggregate of $38 million and $37 million, respectively, per company to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than September 10, 2018. See Note 4 for additional information on joint ownership agreements.

Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, both companies have NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses and policies providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage.

NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted. Alabama Power and Georgia Power each purchase limits based on the projected full cost of replacement power, subject to ownership limitations. Each facility has elected a 12-week deductible waiting period.

A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Vogtle Owners up to $2.75 billion for accidental property damage occurring during construction.

Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The maximum annual assessments for Alabama Power and Georgia Power as of December 31, 2017 under the NEIL policies would be $55 million and $81 million, respectively.

Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.

For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the applicable company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other ~~direct~~expenses incurred. Uninsured losses and ~~indirect subsidiaries.~~other expenses, to the extent not recovered from customers, would be borne by Alabama Power or Georgia Power, as applicable, and could have a material effect on Southern Company's financial condition and results of operations.

All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.

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Southern Company and Subsidiary Companies 2017 Annual Report

10. FAIR VALUE MEASUREMENTS

Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.

Level 1 consists of observable market data in an active market for identical assets or liabilities.

Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.

Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.

In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.

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As of December 31, 2017, 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
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient
As of December 31, 2017:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Energy-related derivatives^(a)(b)	$	331	$	239	$	—	$	—	$	570
Interest rate derivatives	—		1		—		—		1
Foreign currency derivatives	—		129		—		—		129
Nuclear decommissioning trusts:^(c)
Domestic equity	690		82		—		—		772
Foreign equity	62		224		—		—		286
U.S. Treasury and government agency securities	—		251		—		—		251
Municipal bonds	—		68		—		—		68
Corporate bonds	21		315		—		—		336
Mortgage and asset backed securities	—		57		—		—		57
Private equity	—		—		—		29		29
Other	19		12		—		—		31
Cash equivalents	1,455		—		—		—		1,455
Other investments	9		—		1		—		10
Total	$	2,587	$	1,378	$	1	$	29	$	3,995
Liabilities:
Energy-related derivatives^(a)(b)	$	480	$	253	$	—	$	—	$	733
Interest rate derivatives	—		38		—		—		38
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		22		—		22
Total	$	480	$	314	$	22	$	—	$	816


(a)	Energy-related derivatives exclude $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.


(b)	Energy-related derivatives exclude cash collateral of $193 million.


(c)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. See Note 1 under "Nuclear Decommissioning" for additional information.

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Southern Company and Subsidiary Companies 2017 Annual Report

As of December 31, 2016, 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
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient
As of December 31, 2016:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Energy-related derivatives^(a)(b)	$	338	$	333	$	—	$	—	$	671
Interest rate derivatives	—		14		—		—		14
Nuclear decommissioning trusts:^(c)
Domestic equity	589		73		—		—		662
Foreign equity	48		168		—		—		216
U.S. Treasury and government agency securities	—		92		—		—		92
Municipal bonds	—		73		—		—		73
Corporate bonds	22		310		—		—		332
Mortgage and asset backed securities	—		183		—		—		183
Private equity	—		—		—		20		20
Other	11		15		—		—		26
Cash equivalents	1,172		—		—		—		1,172
Other investments	9		—		1		—		10
Total	$	2,189	$	1,261	$	1	$	20	$	3,471
Liabilities:
Energy-related derivatives^(a)(b)	$	345	$	285	$	—	$	—	$	630
Interest rate derivatives	—		29		—		—		29
Foreign currency derivatives	—		58		—		—		58
Contingent consideration	—		—		18		—		18
Total	$	345	$	372	$	18	$	—	$	735


(a)	Energy-related derivatives exclude $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.


(b)	Energy-related derivatives exclude cash collateral of $62 million.


(c)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. See Note 1 under "Nuclear Decommissioning" for additional information.

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

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Southern Company and Subsidiary Companies 2017 Annual Report

categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning 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. See Note 1 under "Nuclear Decommissioning" 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 commencing at the commercial operation date 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, and is evaluated periodically. 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 that are not traded in the open market. The fair value of these investments has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.

As of December 31, 2017 and 2016, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:



	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
As of December 31, 2017	$	29	$	21	Not Applicable	Not Applicable
As of December 31, 2016	$	20	$	25	Not Applicable	Not Applicable

Private equity funds include a fund-of-funds that invests 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. Liquidations are expected to occur at various times over the next 10 years.

As of December 31, 2017 and 2016, other financial instruments for which the carrying amount did not equal fair value were as follows:



	Carrying Amount		Fair Value
	(in millions)
Long-term debt, including securities due within one year:
2017	$	48,151	$	51,348
2016	$	45,080	$	46,286

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, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas.

11. DERIVATIVES

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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 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The 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 under "Financial Instruments" for additional information.

Energy-Related Derivatives

Southern Company and certain subsidiaries 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 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 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 is 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, adversely affect results of operations.

Southern Company Gas also enters into weather derivative contracts as economic hedges of adjusted 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 the statements of income.

Energy-related derivative contracts are accounted for under one of three methods:

Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and 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 OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.

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 December 31, 2017, the net volume of energy-related derivative contracts for natural gas positions totaled 621 million mmBtu for the Southern Company system, with the longest hedge date of 2021 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 of 2026 for derivatives not designated as hedges.

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 gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 32 million mmBtu.

The estimated pre-tax gains (losses) related to energy-related derivatives that will be reclassified from accumulated OCI to earnings for the 12-month period ending December 31, 2018 total $(11) million for Southern Company.

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Southern Company and Subsidiary Companies 2017 Annual Report

Interest Rate Derivatives

Southern Company and certain subsidiaries may also 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 effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. 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, providing an offset, with any difference representing ineffectiveness. 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 December 31, 2017, the following interest rate derivatives were outstanding:



	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) December 31, 2017
	(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
	$	900	1-month LIBOR	0.79%	March 2018	$	1
Fair Value Hedges of Existing Debt
	250		5.40%	3-month LIBOR + 4.02%	June 2018	—
	500		1.95%	3-month LIBOR + 0.76%	December 2018	(3		)
	200		4.25%	3-month LIBOR + 2.46%	December 2019	(1		)
	300		2.75%	3-month LIBOR + 0.92%	June 2020	(2		)
	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	(31		)
Total	$	3,650				$	(36	)

The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending December 31, 2018 total $(20) million. Deferred gains and losses are expected to be amortized into earnings through 2046.

Foreign Currency Derivatives

Southern Company and certain subsidiaries may also 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 effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

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Southern Company and Subsidiary Companies 2017 Annual Report

At December 31, 2017, the following foreign currency derivatives were outstanding:



	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at December 31, 2017
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
	$	677	2.95%	€	600	1.00%	June 2022	$	55
	564		3.78%	500		1.85%	June 2026	51
Total	$	1,241		€	1,100			$	106

The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 2018 total $(23) million.

Derivative Financial Statement Presentation and Amounts

Southern Company and its subsidiaries 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. Fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.

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Southern Company and Subsidiary Companies 2017 Annual Report

At December 31, 2017 and 2016, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:



	2017						2016
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	10		$	43		$	73		$	27
Other deferred charges and assets/Other deferred credits and liabilities	7			24			25			33
Total derivatives designated as hedging instruments for regulatory purposes	$	17		$	67		$	98		$	60
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	3		$	14		$	23		$	7
Interest rate derivatives:
Other current assets/Other current liabilities	1			4			12			1
Other deferred charges and assets/Other deferred credits and liabilities	—			34			1			28
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			25
Other deferred charges and assets/Other deferred credits and liabilities	129			—			—			33
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	133		$	75		$	36		$	94
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	380		$	437		$	489		$	483
Other deferred charges and assets/Other deferred credits and liabilities	170			215			66			81
Interest rate derivatives:
Other current assets/Other current liabilities	—			—			1			—
Total derivatives not designated as hedging instruments	$	550		$	652		$	556		$	564
Gross amounts recognized	$	700		$	794		$	690		$	718
Gross amounts offset^(a)	$	(405	)	$	(598	)	$	(462	)	$	(524	)
Net amounts recognized in the Balance Sheets^(b)	$	295		$	196		$	228		$	194


(a)	Gross amounts offset include cash collateral held on deposit in broker margin accounts of $193 million and $62 million as of December 31, 2017 and 2016, respectively.


(b)	Net amounts of derivative instruments outstanding exclude premiums and intrinsic value associated with weather derivatives of $11 million as of December 31, 2017.

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Southern Company and Subsidiary Companies 2017 Annual Report

At December 31, 2017 and 2016, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows:



	Unrealized Losses							Unrealized Gains
Derivative Category	Balance Sheet Location	2017			2016			Balance Sheet Location	2017		2016
		(in millions)							(in millions)
Energy-related derivatives:	Other regulatory assets, current	$	(34	)	$	(16	)	Other regulatory liabilities, current	$	7	$	56
	Other regulatory assets, deferred	(18		)	(19		)	Other regulatory liabilities, deferred	1		12
Total energy-related derivative gains (losses)^(*)		$	(52	)	$	(35	)		$	8	$	68


(*)	Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million and $8 million as of December 31, 2017 and 2016, respectively.

For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments on the statements of income were as follows:



Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)									Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
	Amount										Amount
Derivative Category	2017			2016			2015			Statements of Income Location	2017			2016			2015
	(in millions)										(in millions)
Energy-related derivatives	$	(47	)	$	18		$	—		Depreciation and amortization	$	(16	)	$	2		$	—
										Cost of natural gas	(2		)	(1		)	—
Interest rate derivatives	(2		)	(180		)	(22		)	Interest expense, net of amounts capitalized	(21		)	(18		)	(9		)
Foreign currency derivatives	140			(58		)	—			Interest expense, net of amounts capitalized	(23		)	(13		)	—
										Other income (expense), net^(*)	160			(82		)	—
Total	$	91		$	(220	)	$	(22	)		$	98		$	(112	)	$	(9	)


(*)	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 euro-denominated notes.

There was no material ineffectiveness recorded in earnings for any period presented.

For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:



Derivatives in Fair Value Hedging Relationships		Gain (Loss)
Derivative Category	Statements of Income Location	2017			2016			2015
		(in millions)
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	(22	)	$	(21	)	$	2

For all years presented, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.

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Southern Company and Subsidiary Companies 2017 Annual Report

For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:



Derivatives Not Designated as Hedging Instruments		Unrealized Gain (Loss) Recognized in Income
		Amount
Derivative Category	Statements of Income Location	2017			2016		2015
		(in millions)
Energy-related derivatives	Wholesale electric revenues	$	(4	)	$	2	$	(5	)
	Fuel	—			—		3
	Natural gas revenues^(*)	(80		)	33		—
	Cost of natural gas	(2		)	3		—
Total		$	(86	)	$	38	$	(2	)


(*)	Excludes gains (losses) recorded in natural gas revenues associated with weather derivatives of $23 million and $6 million for the years ended December 31, 2017 and 2016, respectively.

For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of interest rate derivatives not designated as hedging instruments were immaterial.

Contingent Features

The Company 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 derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At December 31, 2017, the Company had no collateral posted with derivative counterparties to satisfy these arrangements.

At December 31, 2017, the fair value of energy-related and interest rate derivative liabilities with contingent features was $15 million and $7 million, respectively. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $14 million and $7 million for energy-related and interest rate derivative contracts, respectively.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. 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.

The Southern Company system maintains 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, the Company may be required to post collateral. At December 31, 2017, 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 may be required to deposit cash into these accounts. At December 31, 2017, cash collateral held on deposit in broker margin accounts was $193 million.

Southern Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's exposure to counterparty credit risk. Southern Company 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.

Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty

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Southern Company and Subsidiary Companies 2017 Annual Report

and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive 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.

Southern Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

12. ACQUISITIONS AND DISPOSITIONS

Southern Company

Merger with Southern Company Gas

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.

The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:



Southern Company Gas Purchase Price
	(in millions)
Current assets	$	1,557
Property, plant, and equipment	10,108
Goodwill	5,967
Intangible assets	400
Regulatory assets	1,118
Other assets	229
Current liabilities	(2,201		)
Other liabilities	(4,742		)
Long-term debt	(4,261		)
Noncontrolling interest	(174		)
Total purchase price	$	8,001

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes.

The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).

The results of operations for Southern Company Gas have been included in Southern Company's consolidated financial statements from the date of acquisition and consist of operating revenues of $3.9 billion and $1.7 billion and net income of $243 million and $114 million for 2017 and 2016, respectively.

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The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger.



	2016		2015

Operating revenues (in millions)	$	21,791	$	21,430
Net income attributable to Southern Company (in millions)	$	2,591	$	2,665
Basic EPS	$	2.70	$	2.85
Diluted EPS	$	2.68	$	2.84

These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that would be attained in the future.

Acquisition of PowerSecure

In May 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company.

The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:



PowerSecure Purchase Price
	(in millions)
Current assets	$	172
Property, plant, and equipment	46
Intangible assets	106
Goodwill	284
Other assets	4
Current liabilities	(121		)
Long-term debt, including current portion	(48		)
Deferred credits and other liabilities	(14		)
Total purchase price	$	429

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $284 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes.

The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).

The results of operations for PowerSecure have been included in Southern Company's consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented.

Southern Power

During 2017 and 2016, in accordance with its overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, acquired or contracted to acquire the projects discussed below. Also, in March 2016, Southern Power acquired an additional 15% interest in Desert Stateline, 51% of which was initially acquired in 2015. As a result, Southern Power and the class B member are

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Southern Company and Subsidiary Companies 2017 Annual Report

now entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Acquisition-related costs were expensed as incurred and were not material for any of the years presented.

The following table presents Southern Power's acquisition activity for the year ended, and subsequent to, December 31, 2017.



Project Facility	Resource	Seller; Acquisition Date	Approximate Nameplate Capacity (MW)	Location	Southern Power Percentage Ownership			Actual/Expected COD	PPA Contract Period
Business Acquisitions During the Year Ended December 31, 2017
Bethel	Wind	Invenergy Wind Global LLC, January 6, 2017	276	Castro County, TX	100	%		January 2017	12 years
Cactus Flats^(a)	Wind	RES America Developments, Inc. July 31, 2017	148	Concho County, TX	100	%		Third quarter 2018	12 years and 15 years
Business Acquisitions Subsequent to December 31, 2017
Gaskell West 1	Solar	Recurrent Energy Development Holdings, LLC, January 26, 2018	20	Kern County, CA	100% of Class B		(b)	March 2018	20 years


(a)	On July 31, 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. Upon placing the facility in service, Southern Power expects to close on a tax equity partnership agreement that has already been executed, subject to various customary conditions at closing, and will then own 100% of the class B membership interests.


(b)	Southern Power owns 100% of the class B membership interest under a tax equity partnership agreement.

Business Acquisitions During the Year Ended December 31, 2017

Southern Power's aggregate purchase price for acquisitions during the year ended December 31, 2017 was $539 million. The fair values of the assets acquired and liabilities assumed were finalized in 2017 and recorded as follows:



	2017
	(in millions)
Restricted cash	$	16
CWIP	534
Other assets	5
Accounts payable	(16		)
Total purchase price	$	539

In 2017, total revenues of $15 million and net income of $17 million, primarily as a result of PTCs, was recognized by Southern Power related to the 2017 acquisitions. The Bethel facility did not have operating revenues or activities prior to completion of construction and being placed in service, and the Cactus Flats facility is still under construction. Therefore, supplemental pro forma information as though the acquisitions occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.

Construction Projects in Progress

During the year ended December 31, 2017, in accordance with its overall growth strategy, Southern Power continued construction on the 345-MW Mankato expansion project and commenced construction on the Cactus Flats facility. Total aggregate construction costs for these facilities, excluding acquisition costs and including construction costs to complete the subsequently-acquired Gaskell West 1 solar project, are expected to be between $385 million and $430 million. At December 31, 2017, construction costs included in CWIP related to these projects totaled $188 million. The ultimate outcome of these matters cannot be determined at this time.

Development Projects

During 2017, as part of Southern Power's renewable development strategy, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction

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projects, up to 900 MWs in total. Once these wind projects reach commercial operations, which is expected in 2021, they are expected to qualify for 80% PTCs.

During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects expected to be placed in service between 2018 and 2020. In addition, in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Once these wind projects reach commercial operations, they are expected to qualify for 100% PTCs.

The ultimate outcome of these matters cannot be determined at this time.

The following table presents Southern Power's acquisitions for the year ended December 31, 2016.



Project Facility	Resource	Seller, Acquisition Date	Approximate Nameplate Capacity (MW)	Location	Ownership Percentage			Actual COD	PPA Contract Period
Acquisitions for the Year Ended December 31, 2016
Boulder 1	Solar	SunPower November 16, 2016	100	Clark County, NV	51	%	(a)	December 2016	20 years
Calipatria	Solar	Solar Frontier Americas Holding LLC February 11, 2016	20	Imperial County, CA	100	%	(b)	February 2016	20 years
East Pecos	Solar	First Solar, Inc. March 4, 2016	120	Pecos County, TX	100	%		March 2017	15 years
Grant Plains	Wind	Apex Clean Energy Holdings, LLC August 26, 2016	147	Grant County, OK	100	%		December 2016	20 years and 12 years ^(c)
Grant Wind	Wind	Apex Clean Energy Holdings, LLC April 7, 2016	151	Grant County, OK	100	%		April 2016	20 years
Henrietta	Solar	SunPower July 1, 2016	102	Kings County, CA	51	%	(a)	July 2016	20 years
Lamesa	Solar	RES America Developments Inc. July 1, 2016	102	Dawson County, TX	100	%		April 2017	15 years
Mankato ^(d)	Natural Gas	Calpine Corporation October 26, 2016	375	Mankato, MN	100	%		N/A ^(e)	10 years
Passadumkeag	Wind	Quantum Utility Generation, LLC June 30, 2016	42	Penobscot County, ME	100	%		July 2016	15 years
Rutherford	Solar	Cypress Creek Renewables, LLC July 1, 2016	74	Rutherford County, NC	100	%	(b)	December 2016	15 years
Salt Fork	Wind	EDF Renewable Energy, Inc. December 1, 2016	174	Donley and Gray Counties, TX	100	%		December 2016	14 years and 12 years
Tyler Bluff	Wind	EDF Renewable Energy, Inc. December 21, 2016	125	Cooke County, TX	100	%		December 2016	12 years
Wake Wind	Wind	Invenergy October 26, 2016	257	Floyd and Crosby Counties, TX	90.1	%	(f)	October 2016	12 years


(a)	Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction.


(b)	Southern Power originally purchased 90%, with a minority owner owning 10%. During 2017, Southern Power acquired the remaining 10% ownership interest.


(c)	In addition to the 20-year and 12-year PPAs, the facility has a 10-year contract with Allianz Risk Transfer (Bermuda) Ltd.


(d)	Under the terms of the PPA and the expansion PPA, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017.


(e)	The acquisition included a fully operational 375-MW natural gas-fired combined-cycle facility.


(f)	Southern Power owns 90.1%, with the minority owner, Invenergy Wind Global LLC, owning 9.9%.

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Southern Company and Subsidiary Companies 2017 Annual Report

Acquisitions During the Year Ended December 31, 2016

Southern Power's aggregate purchase price for acquisitions during the year ended December 31, 2016 was approximately $2.3 billion. The total aggregate purchase price including minority ownership contributions and the assumption of non-recourse construction debt to Southern Power was approximately $2.6 billion for these acquisitions. In connection with Southern Power's 2016 acquisitions, allocations of the purchase price to individual assets were finalized during the year ended December 31, 2017 with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Henrietta, Mankato, Passadumkeag, Salt Fork, Tyler Bluff, and Wake Wind. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows:



	2016
	(in millions)
CWIP	$	2,354
Property, plant, and equipment	302
Intangible assets ^(a)	128
Other assets	52
Accounts payable	(16		)
Debt	(217		)
Total purchase price	$	2,603

Funded by:
Southern Power ^{(b) (c)}	$	2,345
Noncontrolling interests ^{(d) (e)}	258
Total purchase price	$	2,603


(a)	Intangible assets consist of acquired PPAs that will be amortized over 10- and 20-year terms. The estimated amortization for future periods is approximately $9 million per year. See Note 1 for additional information.


(b)	At December 31, 2016, $461 million is included in acquisitions payable on the balance sheets.


(c)	Includes approximately $281 million of contingent consideration, of which $29 million was payable at December 31, 2017.


(d)	Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders' equity.


(e)	Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests.

Southern Company Gas

Investment in Southern Natural Gas

In September 2016, Southern Company Gas completed its acquisition from Kinder Morgan, Inc. of a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), which is the owner of a 7,000-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. The purchase price of the acquisition was approximately $1.4 billion. The investment in SNG is accounted for using the equity method.

Acquisition of Remaining Interest in SouthStar

SouthStar Energy Services, LLC (SouthStar) is a retail natural gas marketer and markets natural gas to residential, commercial, and industrial customers, primarily in Georgia and Illinois. Southern Company Gas previously had an 85% ownership interest in SouthStar, with Piedmont Natural Gas Company, Inc.'s (Piedmont) owning the remaining 15%. In October 2016, Southern Company Gas purchased Piedmont's 15% interest in SouthStar for $160 million.

Proposed Sale of Elizabethtown Gas and Elkton Gas

On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. The completion of each asset sale is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC. Southern Company Gas and South Jersey Industries, Inc. made joint filings on December 22, 2017 and January 16, 2018 with the

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New Jersey BPU and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018.

The ultimate outcome of these matters cannot be determined at this time.

13. SEGMENT AND RELATED INFORMATION

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 four traditional electric operating companies – ~~the Company,~~Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four 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 the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations.

Southern Company's reportable business segments are the sale of electricity by the four 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 $392 million, $419 million, and $417 million in 2017, 2016, and 2015, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies and Southern Power were $23 million and $119 million, respectively, in 2017 and $11 million and $17 million, respectively, in 2016. 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 technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers; as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the years ended December 31, 2017, 2016, and 2015 was as follows:

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	Electric Utilities
	Traditional Electric Operating Companies			Southern Power			Eliminations			Total		Southern Company Gas		All Other			Eliminations			Consolidated
	(in millions)
2017
Operating revenues	$	16,884		$	2,075		$	(419	)	$	18,540	$	3,920	$	741		$	(170	)	$	23,031
Depreciation and amortization	1,954			503			—			2,457		501		52			—			3,010
Interest income	14			7			—			21		3		11			(9		)	26
Earnings from equity method investments	1			—			—			1		106		(1		)	—			106
Interest expense	820			191			—			1,011		200		490			(7		)	1,694
Income taxes	1,021			(939		)	—			82		367		(307		)	—			142
Segment net income (loss)^(a)(b)(c)	(193		)	1,071			—			878		243		(279		)	—			842
Total assets	72,204			15,206			(325		)	87,085		22,987		2,552			(1,619		)	111,005
Gross property additions	3,836			268			—			4,104		1,525		355			—			5,984
2016
Operating revenues	$	16,803		$	1,577		$	(439	)	$	17,941	$	1,652	$	463		$	(160	)	$	19,896
Depreciation and amortization	1,881			352			—			2,233		238		31			—			2,502
Interest income	6			7			—			13		2		20			(15		)	20
Earnings from equity method investments	2			—			—			2		60		(3		)	—			59
Interest expense	814			117			—			931		81		317			(12		)	1,317
Income taxes	1,286			(195		)	—			1,091		76		(216		)	—			951
Segment net income (loss)^{(a) (b)}	2,233			338			—			2,571		114		(230		)	(7		)	2,448
Total assets	72,141			15,169			(316		)	86,994		21,853		2,474			(1,624		)	109,697
Gross property additions	4,852			2,114			—			6,966		618		41			(1		)	7,624
2015
Operating revenues	$	16,491		$	1,390		$	(439	)	$	17,442	$	—	$	152		$	(105	)	$	17,489
Depreciation and amortization	1,772			248			—			2,020		—		14			—			2,034
Interest income	19			2			1			22		—		6			(5		)	23
Earnings from equity method investments	1			—			—			1		—		(1		)	—			—
Interest expense	697			77			—			774		—		69			(3		)	840
Income taxes	1,305			21			—			1,326		—		(132		)	—			1,194
Segment net income (loss)^{(a) (b)}	2,186			215			—			2,401		—		(32		)	(2		)	2,367
Total assets	69,052			8,905			(397		)	77,560		—		1,819			(1,061		)	78,318
Gross property additions	5,124			1,005			—			6,129		—		40			—			6,169


(a)	Attributable to Southern Company.

(b)

Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $3.4 billion ($2.4 billion after tax) in 2017, $428 million ($264 million after tax) in 2016, and $365 million ($226 million after tax) in 2015. See Note 3 under "Kemper County Energy Facility – Schedule and Cost Estimate" for additional information.


(c)	Segment net income (loss) for the traditional electric operating companies also includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) in 2017. See Note 3 under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.

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Southern Company and Subsidiary Companies 2017 Annual Report

Products and Services



Electric Utilities' Revenues
Year	Retail		Wholesale		Other		Total
	(in millions)
2017	$	15,330	$	2,426	$	784	$	18,540
2016	15,234		1,926		781		17,941
2015	14,987		1,798		657		17,442



Southern Company Gas' Revenues
Year	Gas Distribution Operations		Gas Marketing Services		All Other		Total
	(in millions)
2017	$	3,024	$	860	$	36	$	3,920
2016	1,266		354		32		1,652

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Southern Company and Subsidiary Companies 2017 Annual Report

14. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2017 and 2016 is as follows:



						Consolidated Net Income Attributable to Southern Company			Per Common Share
	Operating Revenues		Operating Income						Basic Earnings			Diluted Earnings					Trading Price Range
Quarter Ended	Operating Revenues		Operating Income						Basic Earnings			Diluted Earnings			Dividends		High		Low
	(in millions)
March 2017	$	5,771	$	1,306		$	658		$	0.66		$	0.66		$	0.5600	$	51.47	$	47.57
June 2017	5,430		(1,594		)	(1,381		)	(1.38		)	(1.37		)	0.5800		51.97		47.87
September 2017	6,201		2,045			1,069			1.07			1.06			0.5800		50.80		46.71
December 2017	5,629		794			496			0.49			0.49			0.5800		53.51		47.92

March 2016	$	3,992	$	940		$	489		$	0.53		$	0.53		$	0.5425	$	51.73	$	46.00
June 2016	4,459		1,185			623			0.67			0.66			0.5600		53.64		47.62
September 2016	6,264		1,917			1,139			1.18			1.17			0.5600		54.64		50.00
December 2016	5,181		587			197			0.20			0.20			0.5600		52.23		46.20

As a result of the revisions to the cost estimate for the Kemper IGCC and its June 2017 suspension, Mississippi Power recorded total pre-tax charges to income related to the Kemper IGCC of $208 million ($185 million after tax) in the fourth quarter 2017, $34 million ($21 million after tax) in the third quarter 2017, $3.0 billion ($2.1 billion after tax) in the second quarter 2017, $108 million ($67 million after tax) in the first quarter 2017, $206 million ($127 million after tax) in the fourth quarter 2016, $88 million ($54 million after tax) in the third quarter 2016, $81 million ($50 million after tax) in the second quarter 2016, and $53 million ($33 million after tax) in the first quarter 2016. See Note 3 under "Kemper County Energy Facility" for additional information.

As a result of the Tax Reform Legislation, the Southern Company system recorded a total income tax benefit of $264 million in the fourth quarter 2017. See Note 5 for additional information.

The Southern Company system's business is influenced by seasonal weather conditions.

Table of Contents Index to Financial Statements

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA

For the Periods Ended December 2013 through 2017

Southern Company and Subsidiary Companies 2017 Annual Report



	2017		2016^(a)		2015		2014		2013
Operating Revenues (in millions)	$	23,031	$	19,896	$	17,489	$	18,467	$	17,087
Total Assets (in millions)^(b)(c)	$	111,005	$	109,697	$	78,318	$	70,233	$	64,264
Gross Property Additions (in millions)	$	5,984	$	7,624	$	6,169	$	6,522	$	5,868
Return on Average Common Equity (percent)^(d)	3.44		10.80		11.68		10.08		8.82
Cash Dividends Paid Per Share of Common Stock	$	2.3000	$	2.2225	$	2.1525	$	2.0825	$	2.0125
Consolidated Net Income Attributable to Southern Company (in millions)^(d)	$	842	$	2,448	$	2,367	$	1,963	$	1,644
Earnings Per Share —
Basic	$	0.84	$	2.57	$	2.60	$	2.19	$	1.88
Diluted	0.84		2.55		2.59		2.18		1.87
Capitalization (in millions):
Common stock equity	$	24,167	$	24,758	$	20,592	$	19,949	$	19,008
Preferred and preference stock of subsidiaries and noncontrolling interests	1,361		1,854		1,390		977		756
Redeemable preferred stock of subsidiaries	324		118		118		375		375
Redeemable noncontrolling interests	—		164		43		39		—
Long-term debt^(b)	44,462		42,629		24,688		20,644		21,205
Total (excluding amounts due within one year)	$	70,314	$	69,523	$	46,831	$	41,984	$	41,344
Capitalization Ratios (percent):
Common stock equity	34.4		35.6		44.0		47.5		46.0
Preferred and preference stock of subsidiaries and noncontrolling interests	1.9		2.7		3.0		2.3		1.8
Redeemable preferred stock of subsidiaries	0.5		0.2		0.3		0.9		0.9
Redeemable noncontrolling interests	—		0.2		0.1		0.1		—
Long-term debt^(b)	63.2		61.3		52.6		49.2		51.3
Total (excluding amounts due within one year)	100.0		100.0		100.0		100.0		100.0
Other Common Stock Data:
Book value per share	$	23.99	$	25.00	$	22.59	$	21.98	$	21.43
Market price per share:
High	$	53.51	$	54.64	$	53.16	$	51.28	$	48.74
Low	46.71		46.00		41.40		40.27		40.03
Close (year-end)	48.09		49.19		46.79		49.11		41.11
Market-to-book ratio (year-end) (percent)	200.5		196.8		207.2		223.4		191.8
Price-earnings ratio (year-end) (times)	57.3		19.1		18.0		22.4		21.9
Dividends paid (in millions)	$	2,300	$	2,104	$	1,959	$	1,866	$	1,762
Dividend yield (year-end) (percent)	4.8		4.5		4.6		4.2		4.9
Dividend payout ratio (percent)	273.2		86.0		82.7		95.0		107.1
Shares outstanding (in thousands):
Average	1,000,336		951,332		910,024		897,194		876,755
Year-end	1,007,603		990,394		911,721		907,777		887,086
Stockholders of record (year-end)	120,803		126,338		131,771		137,369		143,800



(a)	The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under "Merger with Southern Company Gas" for additional information.
(b)	A reclassification of debt issuance costs from Total Assets to Long-term debt of $202 million and $139 million is reflected for years 2014 and 2013, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively.
(c)	A reclassification of deferred tax assets from Total Assets of $488 million and $143 million is reflected for years 2014 and 2013, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively.
(d)	A significant loss to income was recorded by Mississippi Power related to the suspension of the Kemper IGCC in June 2017. Earnings in all periods presented were impacted by losses related to the Kemper IGCC.

Table of Contents Index to Financial Statements

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)

For the Periods Ended December 2013 through 2017

Southern Company and Subsidiary Companies 2017 Annual Report



	2017		2016^(a)		2015		2014		2013
Operating Revenues (in millions):
Residential	$	6,515	$	6,614	$	6,383	$	6,499	$	6,011
Commercial	5,439		5,394		5,317		5,469		5,214
Industrial	3,262		3,171		3,172		3,449		3,188
Other	114		55		115		133		128
Total retail	15,330		15,234		14,987		15,550		14,541
Wholesale	2,426		1,926		1,798		2,184		1,855
Total revenues from sales of electricity	17,756		17,160		16,785		17,734		16,396
Natural gas revenues	3,791		1,596		—		—		—
Other revenues	1,484		1,140		704		733		691
Total	$	23,031	$	19,896	$	17,489	$	18,467	$	17,087
Kilowatt-Hour Sales (in millions):
Residential	50,536		53,337		52,121		53,347		50,575
Commercial	52,340		53,733		53,525		53,243		52,551
Industrial	52,785		52,792		53,941		54,140		52,429
Other	846		883		897		909		902
Total retail	156,507		160,745		160,484		161,639		156,457
Wholesale sales	49,034		37,043		30,505		32,786		26,944
Total	205,541		197,788		190,989		194,425		183,401
Average Revenue Per Kilowatt-Hour (cents):
Residential	12.89		12.40		12.25		12.18		11.89
Commercial	10.39		10.04		9.93		10.27		9.92
Industrial	6.18		6.01		5.88		6.37		6.08
Total retail	9.80		9.48		9.34		9.62		9.29
Wholesale	4.95		5.20		5.89		6.66		6.88
Total sales	8.64		8.68		8.79		9.12		8.94
Average Annual Kilowatt-Hour
Use Per Residential Customer	11,618		12,387		13,318		13,765		13,144
Average Annual Revenue
Per Residential Customer	$	1,498	$	1,541	$	1,630	$	1,679	$	1,562
Plant Nameplate Capacity
Ratings (year-end) (megawatts)	46,936		46,291		44,223		46,549		45,502
Maximum Peak-Hour Demand (megawatts):
Winter	31,956		32,272		36,794		37,234		27,555
Summer	34,874		35,781		36,195		35,396		33,557
System Reserve Margin (at peak) (percent)^(b)	30.8		34.2		33.2		19.8		21.5
Annual Load Factor (percent)	61.4		61.5		59.9		59.6		63.2
Plant Availability (percent):
Fossil-steam	84.5		86.4		86.1		85.8		87.7
Nuclear	94.7		93.3		93.5		91.5		91.5



(a)	The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under "Merger with Southern Company Gas" for additional information.
(b)	Beginning in 2014, system reserve margin is calculated to include unrecognized capacity.

Table of Contents Index to Financial Statements

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)

For the Periods Ended December 2013 through 2017

Southern Company and Subsidiary Companies 2017 Annual Report



	2017	2016^(a)	2015	2014	2013
Source of Energy Supply (percent):
Coal	27.0	30.3	32.3	39.3	36.9
Nuclear	14.5	14.5	15.2	14.8	15.5
Oil and gas	41.9	41.7	42.7	37.0	37.2
Hydro	2.1	2.1	2.6	2.5	3.9
Other	5.4	2.4	0.8	0.4	0.1
Purchased power	9.1	9.0	6.4	6.0	6.4
Total	100.0	100.0	100.0	100.0	100.0
Gas Sales Volumes (mmBtu in millions):
Firm	667	296	—	—	—
Interruptible	95	53	—	—	—
Total	762	349	—	—	—
Traditional Electric Operating Company Customers (year-end) (in thousands):
Residential	4,011	3,970	3,928	3,890	3,859
Commercial^(b)	599	595	590	586	582
Industrial^(b)	18	17	17	17	17
Other	12	11	11	11	9
Total electric customers	4,640	4,593	4,546	4,504	4,467
Gas distribution operations customers	4,623	4,586	—	—	—
Total utility customers	9,263	9,179	4,546	4,504	4,467
Employees (year-end)	31,344	32,015	26,703	26,369	26,300



(a)	The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under "Merger with Southern Company Gas" for additional information.
(b)	A reclassification of customers from commercial to industrial is reflected for years 2013-2015 to be consistent with the rate structure approved by the Georgia PSC. The impact to operating revenues, kilowatt-hour sales, and average revenue per kilowatt-hour by class is not material.

Table of Contents Index to Financial Statements

ALABAMA POWER COMPANY

FINANCIAL SECTION

Table of Contents Index to Financial Statements

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Alabama Power Company 2017 Annual Report

The management of Alabama Power Company (the Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Under management's supervision, an evaluation of the design and effectiveness of the Company's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2017.

/s/ Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President, and Chief Executive Officer

/s/ Philip C. Raymond

Philip C. Raymond

Executive Vice President, Chief Financial Officer, and Treasurer

February 20, 2018

Table of Contents Index to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders and the Board of Directors of Alabama Power Company

Opinion on the Financial Statements

We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (the Company) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2017 and 2016, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements (pages II-186 to II-231) present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company ~~provides electricity~~is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Birmingham, Alabama

February 20, 2018

We have served as the Company's auditor since 2002.

Table of Contents Index to Financial Statements

DEFINITIONS



Term	Meaning
AFUDC	Allowance for funds used during construction
ARO	Asset retirement obligation
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
CCR	Coal combustion residuals
Clean Air Act	Clean Air Act Amendments of 1990
CO₂	Carbon dioxide
DOE	U.S. Department of Energy
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
IRS	Internal Revenue Service
ITC	Investment tax credit
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
MW	Megawatt
NDR	Natural Disaster Reserve
NO_X	Nitrogen oxide
NRC	U.S. Nuclear Regulatory Commission
OCI	Other comprehensive income
power pool	The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power purchase agreement
PSC	Public Service Commission
Rate CNP	Rate Certificated New Plant
Rate CNP Compliance	Rate Certificated New Plant Compliance
Rate CNP PPA	Rate Certificated New Plant Power Purchase Agreement
Rate ECR	Rate Energy Cost Recovery
Rate NDR	Rate Natural Disaster Reserve
Rate RSE	Rate Stabilization and Equalization plan
ROE	Return on equity
S&P	S&P Global Ratings, a division of S&P Global Inc.
SCS	Southern Company Services, Inc. (the Southern Company system service company)
SEC	U.S. Securities and Exchange Commission
SEGCO	Southern Electric Generating Company
SO₂	Sulfur dioxide
Southern Company	The Southern Company
Southern Company Gas	Southern Company Gas and its subsidiaries

Table of Contents Index to Financial Statements

DEFINITIONS

(continued)



Term	Meaning
Southern Company system	Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SEGCO, Southern Nuclear, SCS, Southern Linc, PowerSecure, Inc. (as of May 9, 2016), and other subsidiaries
Southern Linc	Southern Communications Services, Inc.
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
Tax Reform Legislation	The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018
traditional electric operating companies	Alabama Power Company, Georgia Power, Gulf Power, and Mississippi Power

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Alabama Power Company 2017 Annual Report

OVERVIEW

Business Activities

Alabama Power Company (the Company) 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. ~~Southern Power constructs, acquires, owns,~~

Many factors affect the opportunities, challenges, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, includingrisks of the Company's ~~Plant Farley.~~

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, reliability, fuel, capital expenditures, and restoration following major storms. The ~~equity method is used for subsidiaries in which~~Company 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 the Company ~~has significant influence but does not control and~~ for ~~variable interest entities (VIEs) where~~ the ~~Company has an equity investment, but is not the primary beneficiary.~~foreseeable future.

The Company is subject to regulation by the FERC and the Alabama PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.

~~Recently Issued Accounting Standards~~

~~The Financial Accounting Standards Board's (FASB) ASC 606,~~ ~~Revenue from Contracts with Customers,~~ ~~revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017.~~ The Company 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 and preference stock. The Company's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys to evaluate the ~~requirements~~Company's results and generally targets the top quartile of ~~ASC 606.~~ these surveys in measuring performance.

See RESULTS OF OPERATIONS herein for information on the Company's financial performance.

Earnings

The ~~ultimate~~Company's 2017 net income after dividends on preferred and preference stock was $848 million, representing a $26 million, or 3.2%, increase over the previous year. The increase was primarily due to an increase in rates under Rate RSE effective in January 2017 and the impact of a Rate RSE refund recorded in 2016. These increases to income were partially offset by a decrease in retail revenues associated with milder weather, lower customer usage, and an increase in non-fuel operations and maintenance expenses in 2017 as compared to 2016. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate RSE" herein for additional information.

The Company's 2016 net income after dividends on preferred and preference stock was $822 million, representing a $37 million, or 4.7%, increase over the ~~new standard has~~previous year. The increase was due primarily to an increase in retail revenues under Rate CNP Compliance, an increase in weather-related revenues, and a decrease in operations and maintenance expenses not ~~yet been determined.~~

~~On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03,~~ ~~Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs~~ ~~(ASU 2015-03). ASU 2015-03 requires that debt issuance costs~~ related to fuel or Rate CNP Compliance. These increases to income were partially offset by an accrual for a ~~recognized debt liability be presented~~Rate RSE refund, a decrease in ~~the balance sheet as a direct deduction from the carrying amount of that debt liability~~AFUDC equity, and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resultedan increase in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances in long-term debt totaling $39 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 10 for disclosures impacted by ASU 2015-03.depreciation.

~~On May 1, 2015, the FASB issued ASU No. 2015-07,~~ ~~Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)~~ ~~(ASU 2015-07)~~, effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the Company. See Notes 2 and 10 for disclosures impacted by ASU 2015-07.

~~II-167~~

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~~NOTES~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company ~~2015~~2017 Annual Report

~~adoption~~RESULTS OF OPERATIONS

A condensed income statement for the Company follows:



	Amount			Increase (Decrease) from Prior Year
	2017			2017			2016
	(in millions)
Operating revenues	$	6,039		$	150		$	121
Fuel	1,225			(72		)	(45		)
Purchased power	328			(6		)	(17		)
Other operations and maintenance	1,652			142			9
Depreciation and amortization	736			33			60
Taxes other than income taxes	384			4			12
Total operating expenses	4,325			101			19
Operating income	1,714			49			102
Allowance for equity funds used during construction	39			11			(32		)
Interest expense, net of amounts capitalized	305			3			28
Other income (expense), net	(14		)	7			11
Income taxes	568			37			25
Net income	866			27			28
Dividends on preferred and preference stock	18			1			(9		)
Net income after dividends on preferred and preference stock	$	848		$	26		$	37

Operating Revenues

Operating revenues for 2017 were $6.0 billion, reflecting a $150 million increase from 2016. Details of ~~ASU 2015-17, all deferred income tax assets~~operating revenues were as follows:



	Amount
	2017			2016
	(in millions)
Retail — prior year	$	5,322		$	5,234
Estimated change resulting from —
Rates and pricing	362			147
Sales decline	(44		)	(20		)
Weather	(89		)	31
Fuel and other cost recovery	(93		)	(70		)
Retail — current year	5,458			5,322
Wholesale revenues —
Non-affiliates	276			283
Affiliates	97			69
Total wholesale revenues	373			352
Other operating revenues	208			215
Total operating revenues	$	6,039		$	5,889
Percent change	2.6		%	2.1		%

Retail revenues in 2017 were $5.5 billion. These revenues increased $136 million, or 2.6%, in 2017 and ~~liabilities were required~~$88 million, or 1.7%, in 2016, each as compared to ~~be separated into current~~the prior year. The increase in 2017 was primarily due to an increase in rates under Rate RSE effective in January 2017, partially offset by a decrease in fuel revenues and ~~non-current amounts. The new guidance resulted in a reclassification from prepaid expenses of $20 million and accrued income tax of $2 million to non-current accumulated deferred income taxes~~milder weather in the Company’s December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 5 for disclosures impacted by ASU 2015-17.

~~Affiliate Transactions~~

~~The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general~~first and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $438 million, $400 million, and $340 million during 2015, 2014, and 2013, respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.third quarters 2017

The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business and operations. Costs for these services amounted to $243 million, $234 million, and $211 million during 2015, 2014, and 2013, respectively.

The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of non-fuel expenses, which were $11 million in 2015, $13 million in 2014, and $13 million in 2013. Also, Mississippi Power reimburses the Company for any direct fuel purchases delivered from one of the Company's transfer facilities, which were $8 million in 2015, ~~$34 million~~ ~~in 2014, and~~ ~~$27 million~~ ~~in 2013. See Note 4 for additional information.~~

The Company has an agreement with Gulf Power under which the Company has made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Autauga County, Alabama. The transmission improvements were completed in 2014. The Company received $14 million in 2015 and expects to recover approximately $12 million a year from 2016 through 2023 through a tariff with Gulf Power.

The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2015, 2014, or 2013.

~~Also, see Note 4 for information regarding the Company's ownership in a PPA and a gas pipeline ownership agreement with SEGCO.~~

The traditional operating companies, including the Company and Southern Power, may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.

~~II-168~~

Table of Contents Index to Financial Statements

~~NOTES~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company ~~2015~~2017 Annual Report

~~Regulatory Assets and Liabilities~~

~~The Company is subject~~as compared to the ~~provisions of the FASB~~corresponding periods in ~~accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected~~2016. The increase in 2016 was due to ~~be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions~~an increase in revenues ~~associated with amounts that are expected~~under Rate CNP Compliance as a result of increased net investments, partially offset by a decrease in fuel revenues and an accrual for a Rate RSE refund. See Note 3 to ~~be credited~~the financial statements under "Retail Regulatory Matters – Rate RSE" for additional information. See "Energy Sales" herein for a discussion of changes in the volume of energy sold, including changes related to sales decline and weather.

Fuel rates billed to customers ~~through~~are designed to fully recover fluctuating fuel and purchased power costs over a period of time. Fuel revenues generally have no effect on net income because they represent the ~~ratemaking process.~~recording of revenues to offset fuel and purchased power expenses. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate ECR" for additional information.

~~Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:~~Wholesale revenues from power sales to non-affiliated utilities were as follows:

2015
2014
Note
(in millions)
Deferred income tax charges $ 522
$ 525
(a,k)
Loss on reacquired debt 75
80
(b)
Vacation pay 66
65
(c,j)
Under/(over) recovered regulatory clause revenues (97 ) 57
(d)
Fuel-hedging losses 55
53
(e,j)
Other regulatory assets 53
49
(f)
Asset retirement obligations (40 ) (125 ) (a)
Other cost of removal obligations (722 ) (744 ) (a)
Deferred income tax credits (70 ) (72 ) (a)
Nuclear outage 53
56
(d)
Natural disaster reserve (75 ) (84 ) (h)
Other regulatory liabilities (8 ) (17 ) (e,g)
Retiree benefit plans 903
882
(i,j)
Remaining net book value of retired assets 76
13
(l)
Total regulatory assets (liabilities), net $ 791
$ 738



	2017		2016		2015
	(in millions)
Capacity and other	$	154	$	154	$	140
Energy	122		129		101
Total non-affiliated	$	276	$	283	$	241

~~Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:~~

~~(a)~~

~~Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over~~Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the ~~related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.~~


~~(b)~~	~~Recovered over the remaining life of the original issue, which may range up to 50 years.~~


~~(c)~~	~~Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.~~


~~(d)~~	~~Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding 10 years.~~


~~(e)~~	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three and a half years. Upon final settlement, actual costs incurred are recovered through the energy cost ~~recovery clause.~~


~~(f)~~	Comprised of components including generation site selection/evaluation costs, PPA capacity, and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable.

~~(g)~~

Comprised of components including mine reclamation and remediation liabilities, fuel-hedging gains and nuclear fuel disposal fee. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. Nuclear fuel disposal fees are recorded as approved by the Alabama PSC related to potential future fees for nuclear waste disposal. The balance was transferred to Rate ECR in 2015. See Note 3 for additional information.


~~(h)~~	~~Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC.~~


~~(i)~~	~~Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.~~


~~(j)~~	~~Not earning a return as offset in rate base by a corresponding asset or liability.~~


~~(k)~~	Included in the deferred income tax charges are $17 million for 2015 and $18 million for 2014 for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Alabama PSC, over the average remaining service period which may range up to 15 years.


~~(l)~~	~~Recorded and amortized as approved by the Alabama PSC for a period up to 11 years.~~

~~In the event that a portion~~ of the Company's ~~operations is no longer subject to applicable accounting rules~~and the Southern Company system's generation, demand for ~~rate regulation,~~energy within the Southern Company ~~would be required to write off to income or reclassify to accumulated OCI related regulatory assets~~system's electric service territory, and ~~liabilities~~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 ~~specifically recoverable~~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 the Company's variable cost to produce the energy.

In 2017, wholesale revenues from sales to non-affiliates decreased $7 million, or 2.5%, as compared to the prior year. In 2016, wholesale revenues from sales to non-affiliates increased $42 million, or 17.4%, as compared to the prior year primarily due to a $28 million increase in revenues from energy sales and a $14 million increase in capacity revenues. In 2016, KWH sales increased 33.3% primarily due to a new contract that became effective in the first quarter 2016 partially offset by a 12.1% decrease in the price of energy due to lower natural gas prices.

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 and purchases are made in accordance with the Intercompany Interchange Contract (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 ~~regulated rates.~~ the Company's energy cost recovery clause.

In ~~addition,~~2017, wholesale revenues from sales to affiliates increased $28 million, or 40.6%, as compared to the prior year. In 2017, KWH sales increased 31.1% as a result of supporting Southern Company ~~would be required~~system transmission reliability and a 6.9% increase in the price of energy primarily due to ~~determine if any impairment~~higher natural gas prices. In 2016, wholesale revenues from sales to ~~other assets, including plant, exists~~affiliates decreased $15 million, or 17.9%, as compared to the prior year. In 2016, KWH sales decreased 15.7% as a result of lower-cost generation available in the Southern Company system and ~~write down~~a 2.6% decrease in the ~~assets, if impaired,~~price of energy primarily due to ~~their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information.~~lower natural gas prices.

~~II-169~~

Table of Contents Index to Financial Statements

~~NOTES~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company ~~2015~~2017 Annual Report

~~Revenues~~

~~Wholesale capacity~~Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2017 and the percent change from the prior year were as follows:



	Total KWHs	Total KWH Percent Change				Weather-Adjusted Percent Change
	2017	2017		2016		2017		2016
	(in billions)
Residential	17.2	(6.1	)%	1.4	%	(1.2	)%	(0.5	)%
Commercial	13.6	(3.4	)	(0.1	)	(1.3	)	(0.5	)
Industrial	22.7	1.7		(4.6	)	1.7		(4.6	)
Other	0.2	(5.0	)	3.8		(5.0	)	3.8
Total retail	53.7	(2.3	)	(1.5	)	(0.1	)%	(2.2	)%
Wholesale
Non-affiliates	5.5	(6.5	)	37.1
Affiliates	4.2	31.1		(15.7	)
Total wholesale	9.7	6.6		12.5
Total energy sales	63.4	(1.0	)%	0.3	%

Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales in 2017 were 2.3% lower than in 2016. Residential sales and commercial sales decreased 6.1% and 3.4% in 2017, respectively, primarily due to milder weather in the first and third quarters 2017 as compared to the corresponding periods in 2016. Weather-adjusted residential sales were 1.2% lower in 2017 primarily due to lower customer usage resulting from an increase in penetration of energy-efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial sales were 1.3% lower in 2017 primarily due to lower customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial sales increased 1.7% in 2017 as compared to 2016 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, and mining sectors offset by the pipelines and paper sectors.

Retail energy sales in 2016 were 1.5% lower than in 2015. Residential sales increased 1.4% primarily due to warmer weather in the third quarter 2016 as compared to the corresponding period in 2015. Commercial sales remained flat in 2016. Weather-adjusted residential sales were flat in 2016 due to lower customer usage primarily resulting from an increase in efficiency improvements in residential appliances and lighting, partially offset by customer growth. Industrial sales decreased 4.6% in 2016 compared to 2015 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, chemical, pipelines, paper, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global growth conditions constrained growth in the industrial sector in 2016.

See "Operating Revenues" above for a discussion of significant changes in wholesale revenues from ~~PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy~~sales to non-affiliates and ~~other~~wholesale revenues ~~are recognized~~from sales to affiliated companies as ~~services are provided. Unbilled revenues~~ related to ~~retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations~~changes in ~~fuel costs, fuel hedging, the energy component of purchased power costs,~~price and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company continuously monitors the under/over recovered balances and files for revised rates as required or when management deems appropriate, depending on the rate. See Note 3 under "Retail Regulatory Matters – Rate ECR" and "Retail Regulatory Matters – Rate CNP" for additional information.

~~The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.~~KWH sales.

Fuel ~~Costs~~and Purchased Power Expenses

Fuel costs ~~are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization~~constitute one of the ~~cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel.~~

~~See Note 3 under "Retail Regulatory Matters – Nuclear Waste Fund Fee Accounting Order" for additional information.~~

~~Income and Other Taxes~~

The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.

The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.

~~Property, Plant, and Equipment~~

~~The Company's property, plant, and equipment in service consisted of the following at December 31:~~

2015 2014
(in millions)
Generation $ 12,820
$ 11,670
Transmission 3,773
3,579
Distribution 6,432
6,196
General 1,713
1,623
Plant acquisition adjustment 12
12
Total plant in service $ 24,750
$ 23,080

The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders.

~~Nuclear Outage Accounting Order~~

~~In accordance with an Alabama PSC order, nuclear outage operations and maintenance~~largest expenses for the ~~two~~ ~~units at Plant Farley are deferred to a regulatory asset when~~Company. The mix of fuel sources for generation of electricity is determined primarily by the ~~charges actually occur and are then amortized over a subsequent 18-month period with the fall outage costs amortization beginning in January~~unit cost of ~~the following year~~fuel consumed, demand, and the ~~spring outage costs amortization beginning in July~~availability of generating units. Additionally, the ~~same year.~~Company purchases a portion of its electricity needs from the wholesale market.

~~II-170~~

Table of Contents Index to Financial Statements

~~NOTES~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company ~~2015~~2017 Annual Report

~~Depreciation and Amortization~~

Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9% in 2015, 3.3% in 2014 and 3.2% in 2013. Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC and approved by the FERC. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.

In 2014, the Company submitted a depreciation study to the FERC and received authorization to use the recommended rates beginning January 2015. The study was also provided to the Alabama PSC. The new rates resulted in the decrease in the composite depreciation rate for 2015.

~~Asset Retirement Obligations and Other Costs of Removal~~

Asset retirement obligations (ARO) are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Alabama PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.

The liability for AROs primarily relates to the decommissioning of the Company's nuclear facility, Plant Farley, and facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA on April 17, 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. The Company also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates.

Details of the ~~AROs included in the balance sheets are~~Company's generation and purchased power were as follows:



	2017	2016	2015
Total generation (in billions of KWHs)	60.3	60.2	60.9
Total purchased power (in billions of KWHs)	6.4	7.1	6.3
Sources of generation (percent) —
Coal	50	53	54
Nuclear	24	23	24
Gas	20	19	16
Hydro	6	5	6
Cost of fuel, generated (in cents per net KWH) —
Coal	2.60	2.75	2.83
Nuclear	0.75	0.78	0.81
Gas	2.72	2.67	2.94
Average cost of fuel, generated (in cents per net KWH)^(a)	2.14	2.26	2.34
Average cost of purchased power (in cents per net KWH)^(b)	5.29	4.80	5.66



(a)	KWHs generated by hydro are excluded from the average cost of fuel, generated.
(b)	Average cost of purchased power includes fuel, energy, and transmission purchased by the Company for tolling agreements where power is generated by the provider.

2015 2014
(in millions)
Balance at beginning of year $ 829
$ 730

Liabilities incurred 402
1

Liabilities settled (3 ) (3 )
Accretion 53
45

Cash flow revisions 167
56

Balance at end of year $ 1,448
$ 829

Fuel and purchased power expenses were $1.55 billion in 2017, a decrease of $78 million, or 4.8%, compared to 2016. The ~~increase in liabilities incurred and cash flow revisions in 2015 is~~decrease was primarily due to a $67 million net decrease related to the ~~Company's AROs associated with~~volume of KWHs generated and purchased and a $42 million decrease in the ~~impact~~average cost of fuel, partially offset by a $31 million increase in the ~~CCR Rule on its ash~~average cost of purchased power.

Fuel and ~~gypsum facilities.~~purchased power expenses were $1.63 billion in 2016, a decrease of $62 million, or 3.7%, compared to 2015. The decrease was primarily due to a $61 million decrease in the average cost ~~estimates for AROs~~of purchased power, and a $59 million decrease in the average cost of fuel, partially offset by a $49 million increase related to the ~~CCR Rule~~volume of KWHs purchased.

Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are ~~based~~generally offset by energy revenues through the Company's energy cost recovery clause. The Company, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate ECR" for additional information.

Energy purchases from non-affiliates will vary depending on ~~information~~the market prices of wholesale energy as compared to the cost of ~~December 31, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates,~~the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the ~~potential methods for complying with the CCR Rule requirements for closure in place. As further analysis is performed, including evaluation~~availability of the ~~expected method~~Southern Company system's generation.

Fuel

Fuel expenses were $1.2 billion in 2017, a decrease of ~~compliance, refinement~~$72 million, or 5.6%, compared to 2016. The decrease was primarily due to a 12.2% increase in the volume of ~~assumptions~~KWHs generated by hydro, a 5.8% decrease in the volume of KWHs generated by coal, and a 5.5% and 3.9% decrease in the average cost of KWHs generated by coal and nuclear fuel, respectively. These decreases were partially offset by an 8.1% increase in the volume of KWHs generated by nuclear fuel and a 4.0% increase in the volume of KWHs generated by natural gas. Fuel expenses were $1.3 billion in 2016, a decrease of $45 million, or 3.4%, compared to 2015. The decrease was primarily due to a 9.2% decrease in the average cost of KWHs generated by natural gas, which excludes tolling agreements, a 4.2% and 3.9% decrease in the volume of KWHs generated by nuclear fuel and coal, respectively, and a 3.7% decrease in the average cost of KWHs generated by nuclear fuel, partially offset by a 17.4% increase in the volume of KWHs generated by natural gas.

Purchased Power – Affiliates

~~II-171~~Purchased power expense from affiliates was $158 million in 2017, a decrease of $10 million, or 6.0%, compared to 2016. This decrease was primarily due to a 17.2% decrease in the amount of energy purchased due to milder weather partially offset by a 13.9% increase in the average cost per KWH purchased due to higher natural gas prices. Purchased power expense from affiliates was $168 million in 2016, a decrease of $12 million, or 6.7%, compared to 2015. This decrease was primarily due to a

Table of Contents Index to Financial Statements

~~NOTES~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company ~~2015~~2017 Annual Report

~~underlying~~20.7% decrease in the average cost ~~estimates, such as~~per KWH purchased due to lower natural gas prices, partially offset by a 17.5% increase in the ~~quantities~~amount of ~~CCR at each site, and the determination of timing, including the potential for closing ash ponds prior~~energy purchased due to the ~~end~~availability of ~~their currently anticipated useful life, the Company expects to continue to periodically update these estimates.~~

~~The cash flow revisions in 2014 are primarily related~~lower-cost generation compared to the Company's ~~AROs associated with asbestos~~owned generation.

Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at ~~its steam generation facilities.~~

~~Nuclear Decommissioning~~

~~The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The~~each company within the Southern Company ~~has external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds~~system. These purchases are ~~managed and invested~~made in accordance with ~~applicable requirements of various regulatory bodies, including~~ the ~~NRC, the FERC, and the Alabama PSC,~~IIC or other contractual agreements, as well as the IRS. While the Company is allowed to prescribe an overall investment policy to the Funds' managers, the Company and its affiliates are not allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of the Company. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.

The Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis.

At December 31, 2015, investment securities in the Funds totaled $734 million, consisting of equity securities of $521 million, debt securities of $191 million, and $22 million of other securities. At December 31, 2014, investment securities in the Funds totaled $754 million, consisting of equity securities of $583 million, debt securities of $163 million, and $8 million of other securities. These amounts exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases.

Sales of the securities held in the Funds resulted in cash proceeds of $438 million, $244 million, and $279 million in 2015, 2014, and 2013, respectively, all of which were reinvested. For 2015, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $8 million, which included $57 million related to unrealized losses on securities held in the Funds at ~~December 31, 2015. For~~ ~~2014, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were~~ ~~$54 million, which included~~ ~~$19 million~~ ~~related to unrealized gains on securities held in the Funds at~~ ~~December 31, 2014. For~~ ~~2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were~~ ~~$120 million, which included $85 million related to unrealized losses on securities held in the Funds at~~ ~~December 31, 2013~~. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired.

~~Amounts previously recorded in internal reserves are being transferred into the Funds over periods~~ approved by the ~~Alabama PSC.~~FERC.

Other Operations and Maintenance Expenses

In 2017, other operations and maintenance expenses increased $142 million, or 9.4%, as compared to the prior year. Distribution and transmission expenses increased $58 million primarily due to vegetation management expenses. Generation costs increased $38 million primarily due to outage costs. Employee benefit costs, including pension costs, increased $22 million.

In 2016, other operations and maintenance expenses increased $9 million, or 0.6%, as compared to the prior year. Steam production costs increased $28 million primarily due to the timing of generation operating expenses. Transmission and distribution expenses increased $10 million and $7 million, respectively, primarily due to additional vegetation management and other maintenance expenses. These increases were partially offset by a decrease of $32 million in employee benefit costs, including pension costs. The ~~NRC's minimum external funding requirements are based on~~increases in operations and maintenance expenses were primarily Rate CNP compliance-related costs and therefore had no significant impact to net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate CNP Compliance" herein for additional information.

See Note 2 to the financial statements under "Pension Plans" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $33 million, or 4.7%, in 2017 as compared to the prior year primarily due to additional plant in service and an increase in generation-related depreciation rates, effective January 1, 2017, associated with compliance-related steam projects and ARO recovery, partially offset by a ~~generic estimate~~decrease in distribution-related depreciation rates. See Note 1 to the financial statements under "Depreciation and Amortization" for additional information. Depreciation and amortization increased $60 million, or 9.3%, in 2016 as compared to the prior year primarily due to compliance-related steam projects placed in service.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $4 million, or 1.1%, in 2017 as compared to the prior year. In 2016, taxes other than income taxes increased $12 million, or 3.3% in 2016 as compared to the prior year. The increase was primarily due to increases in state and municipal utility license tax bases primarily due to an increase in retail revenues. In addition, ad valorem taxes increased primarily due to an increase in assessed value of property.

Allowance for Equity Funds Used During Construction

AFUDC equity increased $11 million, or 39.3%, in 2017 as compared to the ~~cost~~prior year. The increase was primarily associated with steam, transmission, and nuclear construction projects. AFUDC equity decreased $32 million, or 53.3%, in 2016 as compared to ~~decommission only~~ the ~~radioactive portions~~prior year. The decrease was primarily associated with steam generation capital projects being placed in service. See Note 1 to financial statements under "Allowance for Funds Used During Construction" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $3 million, or 1.0%, in 2017 as compared to the prior year. Interest expense, net of amounts capitalized increased $28 million, or 10.2%, in 2016 as compared to the prior year primarily due to an increase in debt outstanding and a ~~nuclear unit based on~~reduction in the ~~size and type~~amounts capitalized. See FUTURE EARNINGS POTENTIAL – "Financing Activities" herein for additional information.

Other Income (Expense), Net

Other income (expense), net increased $7 million, or 33.3%, in 2017 as compared to the prior year primarily due to increases in unregulated lighting services. Other income (expense), net increased $11 million, or 34.4%, in 2016 as compared to the prior year primarily due to a decrease in donations, partially offset by a decrease in sales of ~~reactor. The Company has filed a plan with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.~~non-utility property.

~~At December 31, the accumulated provisions for decommissioning were as follows:~~

2015 2014
(in millions)
External trust funds $ 734
$ 754
Internal reserves 20
21
Total $ 754
$ 775

~~II-172~~

Table of Contents Index to Financial Statements

~~NOTES~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company ~~2015~~2017 Annual Report

~~Site study costs is the estimate to decommission a facility~~Income Taxes

Income taxes increased $37 million, or 7.0%, in 2017 as ~~of the site study year. The estimated costs of decommissioning as of December 31, 2015 based on the most current study performed in 2013 for Plant Farley are as follows:~~

Decommissioning periods:
Beginning year 2037
Completion year 2076
(in millions)
Site study costs:
Radiated structures $ 1,362
Non-radiated structures 80
Total site study costs $ 1,442

The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.

For ratemaking purposes, the Company's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. The next site study is expected to be conducted in 2018.

~~Amounts previously contributed~~compared to the ~~Funds are currently projected~~prior year primarily due to ~~be adequate~~higher pre-tax earnings, an increase in prior year tax return actualization, and an increase in income tax reserves, partially offset by an increase in state income tax credits. The impact to meet the decommissioning obligations. The Company will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.

~~Allowance for Funds Used During Construction~~

In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The AFUDC composite rate as of December 31 was 8.7% in 2015, 8.8% in 2014, and 9.1% in 2013. AFUDC, net of income taxes as a ~~percent~~result of ~~net income after dividends~~Tax Reform Legislation was not material due to the application of regulatory accounting. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 5 to the financial statements for additional information. Income taxes increased $25 million, or 4.9%, in 2016 as compared to the prior year primarily due to higher pre-tax earnings.

Dividends on Preferred and Preference Stock

Dividends on preferred and preference stock increased $1 million, or 5.9%, in 2017 as compared to the prior year. Dividends on preferred and preference stock decreased $9 million, or 34.6%, in 2016 as compared to the prior year. The decrease was ~~9.3%~~primarily due to the redemption in May 2015, ~~7.9%~~ in ~~2014~~, of certain series of preferred and ~~5.4%~~ in ~~2013~~.preference stock. See Note 6 to the financial statements under "Redeemable Preferred and Preference Stock" for additional information.

~~Impairment~~Effects of ~~Long-Lived Assets and Intangibles~~Inflation

The Company ~~evaluates long-lived assets for impairment when events or changes in circumstances indicate~~is subject to rate regulation that ~~the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred~~ is generally based on ~~either a specific regulatory disallowance or~~the recovery of historical and projected costs. The effects of inflation can create an ~~estimate~~economic loss since the recovery of ~~undiscounted future cash flows attributable~~costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years. See Note 3 to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

~~Cash and Cash Equivalents~~

~~For purposes of~~ the financial statements ~~temporary cash investments~~under "Retail Regulatory Matters – Rate RSE" for additional information.

FUTURE EARNINGS POTENTIAL

General

The Company 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 and to wholesale customers in the Southeast. Prices for electric service provided by the Company to retail customers are ~~considered cash equivalents. Temporary cash investments~~set by the Alabama PSC under cost-based regulatory principles. Prices for wholesale electric service, interconnecting transmission lines, and the exchange of electric power are ~~securities with original maturities~~regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – "Application of ~~90 days~~ ~~or less.~~Critical Accounting Policies and Estimates – Utility Regulation" herein and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information about regulatory matters.

~~Materials~~The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and ~~Supplies~~

~~Generally, materials and supplies~~risks of the Company's primary business of providing electric service. These factors include the ~~average cost~~Company's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of ~~transmission, distribution,~~prudently-incurred costs during a time of increasing costs and ~~generating plant materials. Materials~~limited projected demand growth over the next several years. Future earnings will be impacted by customer growth. 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 ~~charged~~subject to ~~inventory when purchased~~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 ~~then expensed~~the rate of economic growth or ~~capitalized~~decline in the Company'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.

On December 22, 2017, Tax Reform Legislation was signed into law and became effective on January 1, 2018, which, among other things, reduces the federal corporate income tax rate to ~~plant, as appropriate, at weighted average cost when installed.~~21% and changes rates of depreciation and the business interest deduction. See "Income Tax Matters – Federal Tax Reform Legislation" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters – Rate RSE" and "Current and Deferred Income Taxes," respectively, for additional information.

~~II-173~~

Environmental Matters

Table of Contents Index to Financial Statements

~~NOTES~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company ~~2015~~2017 Annual Report

~~Fuel Inventory~~

~~Fuel inventory includes~~flows, and financial condition. Compliance costs may result from the ~~average~~installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these compliance costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of the environmental laws and regulations discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of ~~coal, natural gas, oil, transportation,~~any deployed control technology, and ~~emissions allowances. Fuel is charged to inventory when purchased~~the outcome of pending and/or future legal challenges.

New or revised environmental laws and then expensed, at weighted average cost, as used and recovered by the Company through energy cost recovery rates approved by the Alabama PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.

~~Financial Instruments~~

The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially allregulations could affect many areas of the Company's ~~bulk energy purchases~~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 fully recovered in rates on a timely basis. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate CNP Compliance" for additional information. 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 ~~sales contracts that meet~~financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the ~~definition~~potential to ultimately affect their demand for electricity.

Through 2017, the Company has invested approximately $4.7 billion in environmental capital retrofit projects to comply with environmental requirements, with annual totals of ~~a derivative~~approximately $491 million, $260 million, and $349 million for 2017, 2016, and 2015, respectively. Although the timing, requirements, and estimated costs could change as environmental laws and regulations are ~~excluded~~adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are initiated or completed, the Company's current compliance strategy estimates capital expenditures of $1.4 billion from ~~fair value accounting requirements because they qualify~~2018 through 2022, with annual totals of approximately $581 million in 2018, $110 million in 2019, $163 million in 2020, $258 million in 2021, and $268 million in 2022. These estimates do not include any potential compliance costs associated with the regulation of CO₂ emissions from fossil fuel-fired electric generating units. See "Global Climate Issues" herein for ~~the "normal" scope exception,~~additional information. The Company also anticipates expenditures associated with ash pond closure and ~~are accounted for~~ground water monitoring under the ~~accrual method. Derivative contracts that qualify as cash flow hedges~~Disposal of ~~anticipated transactions~~Coal Combustion Residuals from Electric Utilities rule (CCR Rule), which are reflected in the Company's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.

Environmental Laws and Regulations

Air Quality

The EPA has set National Ambient Air Quality Standards (NAAQS) for six air pollutants (carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and SO₂), which it reviews and revises periodically. Revisions to these standards can require additional emission controls, improvements in control efficiency, or fuel changes which can result in increased compliance and operational costs. NAAQS requirements can also adversely affect the siting of new facilities. In 2015, the EPA published a more stringent eight-hour ozone NAAQS. The EPA plans to complete designations for this rule by no later than April 30, 2018. No areas within the Company's service territory have been or are ~~recoverable through~~anticipated to be designated nonattainment under the ~~Alabama PSC-approved fuel-hedging program result~~2015 ozone NAAQS. In 2010, the EPA revised the NAAQS for SO₂, establishing a new one-hour standard, and is completing designations in multiple phases. The EPA has issued several rounds of area designations and no areas in the ~~deferral~~vicinity of ~~related gains~~Company-owned SO₂ sources have been designated nonattainment under the 2010 one-hour SO₂ NAAQS. However, final eight-hour ozone and ~~losses in OCI or regulatory assets~~SO₂ one-hour designations for certain areas are still pending and, liabilities, respectively, until the hedged transactions occur. If any, immaterial ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualifyif other areas are designated as ~~fair value hedges are marked to market through current period income and are recorded on a net basis~~nonattainment in the ~~statements~~future, increased compliance costs could result.

In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) and its NO_X annual, NO_X seasonal, and SO₂ annual programs. CSAPR is an emissions trading program that addresses the impacts of ~~income. Cash flows~~the interstate transport of SO₂ and NO_X emissions from ~~derivatives are classified on the statement of cash flows~~fossil fuel-fired power plants located in upwind states in the ~~same category as~~eastern half of the ~~hedged item. See Note 11 for additional information regarding derivatives.~~

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2015.

~~The Company is exposed to losses related to financial instruments~~U.S. on air quality in ~~the event of counterparties' nonperformance.~~downwind states. The Company has ~~established controls~~fossil fuel-fired generation subject to ~~determine and monitor~~these requirements. In October 2016, the ~~creditworthiness of counterparties~~EPA published a final rule that revised the CSAPR seasonal NO_X program, establishing more stringent NO_X emissions budgets in ~~order to mitigate the Company's exposure to counterparty credit risk.~~

~~Comprehensive Income~~

~~The objective of comprehensive income is to report a measure of all changes~~Alabama. Increases in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income.

~~Variable Interest Entities~~

The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losseseither future fossil fuel-fired generation or the ~~right~~cost of CSAPR allowances could have a negative financial impact on results of operations for the Company.

The EPA finalized regional haze regulations in 2005 and 2017. These regulations require states, tribal governments, and various federal agencies to ~~receive benefits from~~develop and implement plans to reduce pollutants that impair visibility and demonstrate reasonable progress toward the ~~VIE that could potentially be significant~~goal of restoring natural visibility conditions in certain areas, including national parks and wilderness areas. States must submit a revised state implementation plan (SIP) to the ~~VIE.~~

The Company has established a wholly-owned trust to issue preferred securities. See Note 6 under "Long-Term Debt Payable to an Affiliated Trust" for additional information. However, the Company is not considered the primary beneficiaryEPA by July 31, 2021, demonstrating reasonable progress towards achieving visibility improvement goals. State implementation of ~~the trust. Therefore, the investment~~reasonable progress could require further reductions in ~~the trust is reflected as other investments, and the related loan from the trust is reflected as long-term debt~~SO₂ or NO_X emissions, which could result in ~~the balance sheets.~~increased compliance costs.

~~2. RETIREMENT BENEFITS~~

The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2015, and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2016. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the Alabama PSC and the FERC. For the year ending December 31, 2016, no other postretirement trusts contributions are expected.

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~~NOTES~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company ~~2015~~2017 Annual Report

~~Actuarial Assumptions~~

In 2015, the EPA published a final rule requiring certain states (including Alabama) to revise or remove the provisions of their SIPs regulating excess emissions at industrial facilities, including electric generating facilities, during periods of startup, shut-down, or malfunction (SSM). The ~~weighted average rates assumed~~state excess emission rules provide necessary operational flexibility to affected units during periods of SSM and, if removed, could affect unit availability and result in ~~the actuarial calculations used to determine both the net periodic~~increased operations and maintenance costs for the ~~pension and other postretirement benefit plans for~~Company.

Water Quality

In 2014, the ~~following year and the benefit obligations as~~EPA finalized requirements under Section 316(b) of the ~~measurement date are presented below.~~

Assumptions used to determine net periodic costs: 2015
2014
2013
Pension plans
Discount rate – interest costs 4.18 % 5.02 % 4.27 %
Discount rate – service costs 4.49
5.02
4.27
Expected long-term return on plan assets 8.20
8.20
8.20
Annual salary increase 3.59
3.59
3.59
Other postretirement benefit plans
Discount rate – interest costs 4.04 % 4.86 % 4.06 %
Discount rate – service costs 4.40
4.86
4.06
Expected long-term return on plan assets 7.17
7.34
7.36
Annual salary increase 3.59
3.59
3.59

Assumptions used to determine benefit obligations: 2015
2014
Pension plans

Discount rate 4.67 %
4.18 %
Annual salary increase 4.46

3.59
Other postretirement benefit plans

Discount rate 4.51 %
4.04 %
Annual salary increase 4.46

3.59

~~The Company estimates the expected rate of return on pension plan~~Clean Water Act (CWA) to regulate cooling water intake structures at existing power plants and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classesmanufacturing facilities in order to ~~arrive at the expected return~~minimize their effects on fish and other aquatic life. The regulation requires plant-specific studies to determine applicable measures to protect organisms that either get caught on the ~~entire portfolio relying~~intake screens (impingement) or are drawn into the cooling system (entrainment). The ultimate impact of this rule will depend on the outcome of these plant-specific studies and any additional protective measures required to be incorporated into each ~~trust's target asset allocation and reasonable capital market assumptions. The financial model is~~plant's National Pollutant Discharge Elimination System (NPDES) permit based on ~~four key inputs: anticipated returns~~site-specific factors.

In 2015, the EPA finalized the steam electric effluent limitations guidelines (ELG) rule that set national standards for wastewater discharges from steam electric generating units. The rule prohibits effluent discharges of certain wastestreams and imposes stringent arsenic, mercury, selenium, and nitrate/nitrite limits on scrubber wastewater discharges. The revised technology-based limits and compliance dates may require extensive modifications to existing ash and wastewater management systems or the installation and operation of new ash and wastewater management systems. Compliance with the ELG rule is expected to require capital expenditures and increased operational costs primarily affecting the Company's coal-fired electric generation. Compliance applicability dates range from November 1, 2018 to December 31, 2023 with state environmental agencies incorporating specific applicability dates in the NPDES permitting process based on information provided for each waste stream. The EPA has committed to a new rulemaking that could potentially revise the limitations and applicability dates of the ELG rule. The EPA expects to finalize this rulemaking in 2020. The Company continues to monitor the ELG rule and anticipates that approximately 1,000 MWs of the Company's generation will not be available after the compliance date. The ultimate impact of this rule will depend on any new rule-making that revises the limitation and applicable dates. The Company does not anticipate that the unavailability of any units as a result of the ELG rule will have a material impact on the Company's operations or financial condition.

In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all CWA programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, and canals), which could impact new generation projects and permitting and reporting requirements associated with the installation, expansion, and maintenance of transmission and distribution projects. On July 27, 2017, the EPA and the Corps proposed to rescind the 2015 WOTUS rule. The WOTUS rule has been stayed by ~~asset class (based~~the U.S. Court of Appeals for the Sixth Circuit since late 2015, but on January 22, 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction over the pending challenges to the rule. On February 6, 2018, the EPA and the Corps published a final rule delaying implementation of the 2015 WOTUS rule to 2020.

Coal Combustion Residuals

In 2015, the EPA finalized non-hazardous solid waste regulations for the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments (CCR units) at active generating power plants. The CCR Rule requires CCR units to be evaluated against a set of performance criteria and potentially closed if minimum criteria are not met. Closure of existing CCR units could require installation of equipment and infrastructure to manage CCR in accordance with the rule. The EPA has announced plans to reconsider certain portions of the CCR Rule by no later than December 2019, which could result in changes to deadlines and corrective action requirements.

Based on ~~historical returns), each trust's target asset allocation, an anticipated inflation rate,~~cost estimates for closure in place and monitoring of ash ponds pursuant to the ~~projected impact of a periodic rebalancing of each trust's portfolio.~~

~~For purposes of its December 31, 2015 measurement date,~~CCR Rule, the Company ~~adopted new mortality tables~~recorded AROs for ~~its pension~~each CCR unit in 2015. As further analysis is performed and ~~other postretirement benefit plans, which reflect decreased life expectancies in~~closure details are developed, the ~~U.S. The adoption~~Company will continue to periodically update these cost estimates as necessary. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of ~~new mortality tables reduced the projected benefit obligations~~Removal" for additional information regarding the Company's ~~pension plans and other postretirement benefit plans by approximately $51 million and $9 million, respectively.~~

Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached
Pre-65 6.50 % 4.50 % 2024
Post-65 medical 5.50
4.50
2024
Post-65 prescription 10.00
4.50
2025

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~~NOTES~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company ~~2015~~2017 Annual Report

~~An annual increase or decrease in the assumed medical care cost trend rate of~~ 1% ~~would affect the APBO and the service and interest cost components at~~ ~~December 31, 2015~~ ~~as follows:~~

1 Percent
Increase

1 Percent
Decrease
(in millions)
Benefit obligation $ 29
$ (25 )
Service and interest costs 1
(1 )

~~Pension Plans~~

~~The total accumulated benefit obligation for the pension plans was $2.3 billion at~~ ~~December 31, 2015~~ ~~and~~ ~~$2.4 billion~~ at ~~December 31, 2014. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~ ~~were as follows:~~

2015 2014
(in millions)
Change in benefit obligation
Benefit obligation at beginning of year $ 2,592
$ 2,112
Service cost 59
48
Interest cost 106
103
Benefits paid (120 ) (100 )
Actuarial loss (gain) (131 ) 429
Balance at end of year 2,506
2,592
Change in plan assets
Fair value of plan assets at beginning of year 2,396
2,278
Actual return (loss) on plan assets (9 ) 207
Employer contributions 12
11
Benefits paid (120 ) (100 )
Fair value of plan assets at end of year 2,279
2,396
Accrued liability $ (227 ) $ (196 )

At ~~December 31, 2015~~, the projected benefit obligations for the qualified and non-qualified pension plans were $2.4 billion and $124 million, respectively. All pension plan assets are related to the qualified pension plan.

~~Amounts recognized in the balance sheets at~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~ ~~related to the Company's pension plans consist of the following:~~

2015 2014
(in millions)
Other regulatory assets, deferred $ 822
$ 827
Other current liabilities (11 ) (10 )
Employee benefit obligations (216 ) (186 )

~~Presented below are the amounts included in regulatory assets at~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~ ~~related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2016.~~

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~~NOTES (continued)~~

~~Alabama Power Company 2015 Annual Report~~

2015 2014
Estimated
Amortization
in 2016
(in millions)
Prior service cost $ 6
$ 12
$ 3
Net (gain) loss 816
815
40
Regulatory assets $ 822
$ 827

Global Climate Issues

~~The changes in~~In 2015, the ~~balance of regulatory assets related to the defined benefit pension plans for the years ended~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~ ~~are presented in the following table:~~

2015 2014
(in millions)
Regulatory assets:
Beginning balance $ 827
$ 476
Net (gain) loss 56
389
Reclassification adjustments:
Amortization of prior service costs (6 ) (7 )
Amortization of net gain (loss) (55 ) (31 )
Total reclassification adjustments (61 ) (38 )
Total change (5 ) 351
Ending balance $ 822
$ 827

~~Components of net periodic pension cost were as follows:~~

2015 2014 2013
(in millions)
Service cost $ 59
$ 48
$ 52
Interest cost 106
103
93
Expected return on plan assets (178 ) (168 ) (157 )
Recognized net loss 55
31
52
Net amortization 6
7
7
Net periodic pension cost $ 48
$ 21
$ 47

Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over ~~five years~~ rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.

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~~NOTES (continued)~~

~~Alabama Power Company 2015 Annual Report~~

~~Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At~~ ~~December 31, 2015, estimated benefit payments were as follows:~~

Benefit
Payments
(in millions)
2016 $ 114
2017 119
2018 124
2019 129
2020 134
2021 to 2025 740

~~Other Postretirement Benefits~~

~~Changes in the APBO and in the fair value of plan assets during the plan years ended~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~ ~~were as follows:~~

2015 2014
(in millions)
Change in benefit obligation
Benefit obligation at beginning of year $ 503
$ 431
Service cost 6
5
Interest cost 20
20
Benefits paid (27 ) (27 )
Actuarial loss (gain) (7 ) 71
Plan amendment 7
—
Retiree drug subsidy 3
3
Balance at end of year 505
503
Change in plan assets
Fair value of plan assets at beginning of year 392
389
Actual return (loss) on plan assets (6 ) 23
Employer contributions 1
4
Benefits paid (24 ) (24 )
Fair value of plan assets at end of year 363
392
Accrued liability $ (142 ) $ (111 )

~~Amounts recognized in the balance sheets at~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~ ~~related to the Company's other postretirement benefit plans consist of the following:~~

2015 2014
(in millions)
Other regulatory assets, deferred $ 95
$ 68
Other regulatory liabilities, deferred (13 ) (14 )
Employee benefit obligations (142 ) (111 )

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~~NOTES (continued)~~

~~Alabama Power Company 2015 Annual Report~~

~~Presented below are the amounts included in net regulatory assets (liabilities) at~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~ ~~related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2016.~~

2015 2014
Estimated
Amortization
in 2016
(in millions)
Prior service cost $ 19
$ 15
$ 4
Net (gain) loss 63
39
2
Net regulatory assets $ 82
$ 54

~~The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~ ~~are presented in the following table:~~

2015 2014
(in millions)
Net regulatory assets (liabilities):
Beginning balance $ 54
$ (15 )
Net (gain) loss 25
73
Change in prior service costs 8
—
Reclassification adjustments:
Amortization of prior service costs (3 ) (4 )
Amortization of net gain (loss) (2 ) —
Total reclassification adjustments (5 ) (4 )
Total change 28
69
Ending balance $ 82
$ 54

~~Components of the other postretirement benefit plans' net periodic cost were as follows:~~

2015 2014 2013
(in millions)
Service cost $ 6
$ 5
$ 6
Interest cost 20
20
19
Expected return on plan assets (26 ) (25 ) (23 )
Net amortization 5
4
5
Net periodic postretirement benefit cost $ 5
$ 4
$ 7

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~~NOTES (continued)~~

~~Alabama Power Company 2015 Annual Report~~

Benefit
Payments

Subsidy
Receipts
Total
(in millions)
2016 $ 33
$ (3 ) $ 30
2017 34
(3 ) 31
2018 34
(3 ) 31
2019 35
(4 ) 31
2020 36
(4 ) 32
2021 to 2025 184
(20 ) 164

~~Benefit Plan Assets~~

Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.

~~The composition of the Company's pension plan and other postretirement benefit plan assets as of~~ ~~December 31, 2015~~ ~~and~~ ~~2014, along with the targeted mix of assets for each plan, is presented below:~~

Target 2015 2014
Pension plan assets:
Domestic equity 26 % 30 % 30 %
International equity 25
23
23
Fixed income 23
23
27
Special situations 3
2
1
Real estate investments 14
16
14
Private equity 9
6
5
Total 100 % 100 % 100 %
Other postretirement benefit plan assets:
Domestic equity 48 % 45 % 48 %
International equity 20
20
20
Domestic fixed income 24
27
26
Special situations 1
1
—
Real estate investments 4
5
4
Private equity 3
2
2
Total 100 % 100 % 100 %

The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a

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~~NOTES (continued)~~

~~Alabama Power Company 2015 Annual Report~~

~~formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices.~~

~~Investment Strategies~~

~~Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above:~~

~~Domestic equity.~~ ~~A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.~~

~~International equity.~~ ~~A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.~~

~~Fixed income.~~ ~~A mix of domestic and international bonds.~~

~~Trust-owned life insurance (TOLI).~~ ~~Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio.~~

~~Special situations.~~ Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.

~~Real estate investments.~~ ~~Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.~~

~~Private equity.~~ Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.

~~Benefit Plan Asset Fair Values~~

~~Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

~~Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:~~

~~Domestic and international equity.~~Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.

~~Fixed income.~~Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.

~~TOLI.~~ Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.

~~Real estate investments and private equity.~~Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.

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~~NOTES (continued)~~

~~Alabama Power Company 2015 Annual Report~~

~~The fair values of pension plan assets as of~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~ are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.



*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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~~NOTES (continued)~~

~~Alabama Power Company 2015 Annual Report~~



*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

~~The fair values of other postretirement benefit plan assets as of~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~ are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.

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~~NOTES (continued)~~

~~Alabama Power Company 2015 Annual Report~~



*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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~~NOTES (continued)~~

~~Alabama Power Company 2015 Annual Report~~



*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

~~Employee Savings Plan~~

The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2015, 2014, and 2013 were $22 million, $21 million, and ~~$20 million, respectively.~~

~~3. CONTINGENCIES AND REGULATORY MATTERS~~

~~General Litigation Matters~~

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused byEPA published final rules limiting CO₂ emissions from new, modified, and reconstructed fossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO₂ emission performance standards for existing units (known as the Clean Power Plan or CPP). In February 2016, the U.S. Supreme Court granted a stay of the CPP, which will remain in effect through the resolution of litigation in the U.S. Court of Appeals for the District of Columbia challenging the legality of the CPP and any review by the U.S. Supreme Court. On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including review of the CPP and other CO₂emissions ~~CCR,~~rules. On October 10, 2017, the EPA published a proposed rule to repeal the CPP and, ~~alleged exposure~~on December 28, 2017, published an advanced notice of proposed rulemaking regarding a CPP replacement rule.

In 2015, parties to ~~hazardous materials, and/or requests~~the United Nations Framework Convention on Climate Change, including the United States, adopted the Paris Agreement, which established a non-binding universal framework for ~~injunctive relief in connection with such matters.~~addressing greenhouse gas (GHG) emissions based on nationally determined contributions. On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate ~~outcome~~impact of ~~such pending~~this agreement or ~~potential litigation against~~any renegotiated agreement depends on its implementation by participating countries.

The EPA's GHG reporting rule requires annual reporting of GHG emissions expressed in terms of metric tons of CO₂ equivalent emissions for a company's operational control of facilities. Based on ownership or financial control of facilities, the ~~Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that~~Company's 2016 GHG emissions were approximately 38 million metric tons of CO₂ equivalent. The preliminary estimate of the ~~ultimate liabilities, if any, arising from such current proceedings would have a material effect~~Company's 2017 GHG emissions on the ~~Company's financial statements.~~

~~Environmental Matters~~

~~Environmental Remediation~~

~~The Company must comply with environmental laws and regulations that cover the handling and disposal~~same basis is approximately 37 million metric tons of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up affected sites. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year

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~~NOTES (continued)~~

~~Alabama Power Company 2015 Annual Report~~

~~presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation.~~

~~Nuclear Fuel Disposal Costs~~

Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into a contract with the Company that requires the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plant Farley beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, the Company has pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract.

In December 2014, the Court of Federal Claims entered a judgment in favor of the Company in its spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. On March 19, 2015, the Company recovered approximately $26 million. In November 2015, the Company applied the retail-related proceeds to offset the nuclear fuel expense under Rate ECR. See "Retail Regulatory Matters – Nuclear Waste Fund Accounting Order" herein for additional information. In December 2015, the Company credited the wholesale-related proceeds to each wholesale customer.

In March 2014, the Company filed an additional lawsuit against the U.S. government for the costs of continuing to store spent nuclear fuel at Plant Farley for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2015 for any potential recoveries from this lawsuit. The final outcome of this matter cannot be determined at this time; however, no material impact on the Company's net income is expected.

~~At Plant Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of the plant.~~CO₂ equivalent.

FERC Matters

The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in ~~June~~ 2014, which included continued reliance on the energy auction as tailored mitigation. ~~On April 27,~~In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing ~~on May 27, 2015~~ and ~~on June 26, 2015~~ filed their response with the ~~FERC.~~ FERC in 2015.

In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.

The ultimate outcome of ~~this matter~~these matters cannot be determined at this time.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

Retail Regulatory Matters

The Company's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. The Company 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 the Company. See Note 1 to the financial statements and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information regarding the Company's rate mechanisms and accounting orders.

Rate RSE

The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon the Company's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. ~~Retail rates remain unchanged when the WCE ranges between 5.75% and 6.21%.~~ Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If the Company's actual retail return is above the allowed WCE range, ~~customer refunds~~the excess will be ~~required;~~refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.

At December 31, 2016, the Company's retail return exceeded the allowed WCE range which resulted in the Company establishing a $73 million Rate RSE refund liability. In ~~2013, the~~accordance with an Alabama PSC ~~approved a revision~~order issued on February 14, 2017, the Company applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below.

Effective in January 2017, Rate RSE ~~effective for calendar year 2014. This revision established~~increased 4.48%, or $245 million annually. At December 31, 2017, the Company's actual retail return was within the allowed WCE range of 5.75% to 6.21% with an adjusting point of 5.98% and provided eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if the Company (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.

~~The Rate RSE increase for 2015 was 3.49% or $181 million annually, and was effective January~~range. On December 1, ~~2015. On November 30, 2015,~~2017, the Company made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year ~~2016.~~2018. Projected earnings were within the specified ~~WCE~~ range; therefore, retail rates under Rate RSE remained unchanged for ~~2016.~~2018.

~~II-186~~

~~Table~~In conjunction with Rate RSE, the Company has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of ~~ContentsIndex to Financial Statements~~a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time.

~~NOTES (continued)~~

~~Alabama Power Company 2015 Annual Report~~

Rate CNP PPA

The Company's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail ~~service under Rate CNP.~~service. The Company may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March ~~3, 2015,~~7, 2017, the Alabama PSC issued a consent order that the Company leave in effect the current Rate CNP PPA factor for billings for the period April 1, ~~2015~~2017 through March 31, ~~2016.~~2018. No adjustment to Rate CNP PPA is expected in ~~2016. As of~~2018.

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company eliminated the under recovered balance in Rate CNP PPA at December 31, ~~2015,~~2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," the Company ~~had an~~utilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under ~~recovered certificated PPA balance~~recovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of ~~$99 million~~the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is ~~included in deferred under recovered regulatory clause revenues in~~expected to occur within the ~~balance sheet.~~next two to four years. The Company's current depreciation study became effective January 1, 2017.

Rate CNP ~~Environmental allowed~~Compliance

Rate CNP Compliance allows for the recovery of the Company's retail costs associated with ~~environmental~~ laws, regulations, and other such mandates. On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting the Company's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. The Company was limited to recover $50 million of non-environmental compliance costs for the year 2015. Additional non-environmental compliance costs were recovered through Rate RSE. Customer rates were not impacted by this order in 2015; therefore, the modification increased the under recovered position for Rate CNP Compliance during 2015. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital.

Revenues for Rate CNP Compliance, ~~increased 1.5%,~~as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on the Company's revenues or ~~$75~~net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company reclassified $36 million ~~annually,~~of its under recovered balance in Rate CNP Compliance to a separate regulatory asset. The amortization of the new regulatory

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, ~~2015. As of~~2017.

On December ~~31, 2015,~~5, 2017, the Alabama PSC issued a consent order that the Company ~~had an~~leave in effect for 2018 the factors associated with the Company's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered ~~compliance clause balance of $43 million, which is included in under recovered regulatory clause revenues~~amounts associated with 2018 will be reflected in the ~~balance sheet.~~2019 filing.

Rate ECR

The Company has established energy cost recovery rates under the Company's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. The Company, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on the Company's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH.

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company reclassified $36 million of its under recovered balance in Rate ECR to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2017.

On December ~~2014,~~5, 2017, the Alabama PSC issued a consent order that the Company leave in effect for ~~2015~~2018 the energy cost recovery rates which began in 2017. Therefore, the Rate ECR factor as of ~~2.681~~January 1, 2018 remained at 2.015 cents per KWH.

On December 1, 2015, the Alabama PSC approved a decrease in the Company’s Rate ECR factor from 2.681 to 2.030 cents per KWH, 6.7%, or $370 million annually, based upon projected billings, effective January 1, 2016. The approved decrease in the Rate ECR factor will have no significant effect on the Company's net income, but will decrease operating cash flows related to fuel cost recovery in 2016 when compared to 2015. The rate will return to ~~2.681 cents per KWH in 2017 and~~ 5.910 cents per KWH in ~~2018,~~2019, absent a further order from the Alabama PSC.

Rate NDR

In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million. The Company expects to collect approximately $16 million annually until the reserve balance is restored to $75 million. The NDR balance at December 31, ~~2015 totaled $238 million~~2017 was $38 million.

Environmental Accounting Order

Based on an order from the Alabama PSC, the Company is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. The regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as ~~compared~~established prior to ~~$47 million at~~the decision regarding early retirement through Rate CNP Compliance. See "Environmental Matters – Environmental Laws and Regulations" herein for additional information regarding environmental regulations.

Income Tax Matters

Federal Tax Reform Legislation

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

Regulated utility businesses can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. Projects with binding contracts before September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the Protecting Americans from Tax Hikes (PATH) Act.

In addition, under the Tax Reform Legislation, net operating losses (NOL) generated after December 31, ~~2014. At~~2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income in the subsequent tax year. The projected reduction of Southern Company's consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards.

For the year ended December 31, ~~2015, $238~~2017, implementation of the Tax Reform Legislation resulted in an estimated net tax expense of $3 million, ~~is included~~a $271 million decrease in ~~other~~regulatory assets, and a $2.0 billion increase in regulatory liabilities, ~~current.~~ primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities.

The ~~over recovered fuel costs at December 31, 2014 are included in deferred over recovered~~Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory ~~clause revenues. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand,~~treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the ~~price~~Alabama PSC. On January 31, 2018, SCS, on behalf of ~~energy. A change in any~~the traditional electric operating companies (including the Company), filed with the FERC a reduction to the Company's open access transmission tariff charge for 2018 to reflect the revised federal corporate tax rate. See Note 3 to the financial statements under "Regulatory Matters – Rate RSE" for additional information.

See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Federal Tax Reform Legislation" for additional information.

The ultimate outcome of these ~~factors~~matters cannot be determined at this time.

Bonus Depreciation

Other Matters

The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, water, land, and protection of other natural resources, 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 predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.

Utility Regulation

The Company is subject to retail regulation by the Alabama PSC and wholesale regulation by the FERC. As a result, the Company applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.

Federal Tax Reform Legislation

Following the enactment of Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters – Rate RSE" and "Current and Deferred Income Taxes," respectively, for additional information.

Asset Retirement Obligations

The liability for AROs primarily relates to the decommissioning of the Company's nuclear facility, Plant Farley, and facilities that are subject to the CCR Rule, principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal related to ongoing repair and maintenance, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, asbestos containing material within long-term assets not subject to ongoing repair and maintenance activities, and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.

The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

Given the significant judgment involved in estimating AROs, the Company considers the liabilities for AROs to be critical accounting estimates.

Pension and Other Postretirement Benefits

The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.

Key elements in determining the Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on the Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, the Company discounts the future related cash flows using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, the Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. Beginning in 2016, the Company adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost component of net periodic pension and other postretirement benefit plan expense decreased by approximately $24 million in 2016.

A 25 basis point change in any significant assumption (discount rate, salaries, or long-term return on plan assets) would result in an $9 million or less change in total annual benefit expense and a $128 million or less change in projected obligations.

The Company recorded pension costs of $9 million, $11 million, and $48 million in 2017, 2016, and 2015, respectively. Postretirement benefit costs for the Company were $3 million, $4 million, and $5 million in 2017, 2016, and 2015, respectively. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension and other postretirement benefit costs is capitalized based on construction-related labor charges. Pension and other postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income.

See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.

Contingent Obligations

The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject it to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's results of operations, cash flows, or financial condition.

Recently Issued Accounting Standards

Revenue

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed separately from revenues under ASC 606. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.

The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.

Leases

In February 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. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.

The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers, railcars, and a PPA where the Company is the lessee and outdoor lighting and to land where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.

Other

On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company's financial condition remained stable at December 31, 2017. The Company's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. Capital expenditures and other

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

investing activities include investments to meet projected long-term demand requirements, to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units, to expand and improve transmission and distribution facilities, and for restoration following major storms. Operating cash flows provide a substantial portion of the Company's cash needs. For the three-year period from 2018 through 2020, the Company's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. The Company plans to finance future cash needs in excess of its operating cash flows primarily through external securities issuances, borrowings from financial institutions, or equity contributions from Southern Company. The Company plans to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs. The Company 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 "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.

The Company's investments in the qualified pension plan and the nuclear decommissioning trust funds increased in value as of December 31, 2017 as compared to December 31, 2016. No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated during 2018. The Company's funding obligations for the nuclear decommissioning trust fund are based on the most recent site study, and the next study is expected to be conducted in 2018. See Notes 1 and 2 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.

Net cash provided from operating activities totaled $1.8 billion for 2017, a decrease of $112 million as compared to 2016. The decrease in cash provided from operating activities was primarily due to the timing of income tax payments in 2017 and the receipt of income tax refunds in 2016 as a result of bonus depreciation, partially offset by the voluntary contribution to the qualified pension plan in 2016. Net cash provided from operating activities totaled $1.9 billion for 2016, a decrease of $193 million as compared to 2015. The decrease in cash provided from operating activities was primarily due to the collection of fuel cost recovery revenues and the voluntary contribution to the qualified pension plan, partially offset by the timing of income tax payments and refunds associated with bonus depreciation.

Net cash used for investing activities totaled $1.9 billion for 2017, $1.4 billion for 2016, and $1.5 billion for 2015. These activities were primarily related to gross property additions for environmental, steam generation, distribution, and transmission assets.

Net cash provided from financing activities totaled $163 million in 2017 primarily due to issuances of long-term debt and additional capital contributions from Southern Company, partially offset by the payment of common stock dividends and maturities of long-term debt. Net cash used for financing activities totaled $285 million in 2016 primarily due to the payment of common stock dividends and a redemption of long-term debt, partially offset by issuances of long-term debt and additional capital contributions from Southern Company. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for 2017 included increases of $1.3 billion in property, plant, and equipment primarily due to additions to distribution and transmission facilities and environmental and steam generation assets and $1.1 billion in long-term debt. Other significant changes included an increase of $2.0 billion in deferred credits related to income taxes and decreases of $1.9 billion in accumulated deferred income taxes primarily due to the change in tax rate resulting from Tax Reform Legislation and $0.6 billion in securities due within one year. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 5 to the financial statements for additional information.

The Company's ratio of common equity to total capitalization plus short-term debt was 46.3% and 46.2% at December 31, 2017 and 2016, respectively. See Note 6 to the financial statements for additional information.

Sources of Capital

The Company 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.

Security issuances are subject to regulatory approval by the Alabama PSC. Additionally, with respect to the public offering of securities, the Company files registration statements with the SEC under the Securities Act of 1933, as amended. The amounts of securities authorized by the Alabama PSC are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company in the Southern Company system.

The Company'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 December 31, 2017, the Company had approximately $544 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2017 were as follows:



Expires										Expires Within One Year
2018		2020		2022		Total		Unused		Term Out		No Term Out
(in millions)						(in millions)				(in millions)
$	35	$	500	$	800	$	1,335	$	1,335	$	—	$	35

See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.

In May 2017 and September 2017, the Company amended its $800 million and $500 million multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022 and 2018 to 2020, respectively, as reflected in the table above.

Most of these bank credit arrangements, as well as the Company's term loan arrangements, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of the Company. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the Company defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2017, the Company 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, the Company expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, the Company 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 the Company's pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was $854 million as of December 31, 2017. In addition, at December 31, 2017, the Company had $120 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.

The Company also has substantial cash flow from operating activities and access to the capital markets, including a commercial paper program, to meet liquidity needs. The Company may meet short-term cash needs through its commercial paper program. The Company 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 the Company and the other traditional electric operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.

Details of short-term borrowings were as follows:



	Short-term Debt at the End of the Period				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)
December 31, 2017	$	3	3.7	%	$	25	1.3	%	$	223
December 31, 2016	$	—	—	%	$	16	0.6	%	$	200
December 31, 2015	$	—	—	%	$	14	0.2	%	$	100


(*)	Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2017, 2016, and 2015.

The Company believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

Financing Activities

In February 2017, the Company repaid at maturity $200 million aggregate principal amount of Series 2007A 5.55% Senior Notes.

In March 2017, the Company issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay the Company's short-term indebtedness and for general corporate purposes, including the Company's continuous construction program.

In August 2017, the Company repaid at maturity $36.1 million aggregate principal amount of Series 1993-A, 1993-B, and 1993-C Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project).

In September 2017, the Company issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of 5.83% Class A Preferred Stock and for other general corporate purposes, including the Company's continuous construction program.

In October 2017, the Company repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes.

In November 2017, the Company issued $550 million aggregate principal amount of Series 2017B 3.70% Senior Notes due December 1, 2047. The proceeds were used for general corporate purposes, including the Company's continuous construction program.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company 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.

Credit Rating Risk

At December 31, 2017, the Company 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.

The maximum potential collateral requirements under these contracts at December 31, 2017 were as follows:



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	1
At BBB- and/or Baa3	$	2
Below BBB- and/or Baa3	$	323

Included in these amounts are certain agreements that could require collateral in the event that either the Company or 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 the Company to access capital markets and would be likely to impact the cost at which it does so.

On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the Company) from stable to negative.

On January 19, 2018, Moody's revised its rating outlook for the Company from stable to negative.

While it is unclear how the credit rating agencies and regulatory authorities may respond to 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 the Company, may be negatively impacted. Absent actions by Southern Company and its subsidiaries, including the Company, to mitigate the resulting impacts, which, among other alternatives, could include adjusting capital structure and/or monetizing regulatory assets, the Company's credit ratings could be negatively affected. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate RSE" for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

Market Price Risk

Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The 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.

To mitigate future exposure to changes in interest rates, the Company may enter into derivatives designated as hedges. The weighted average interest rate on $1.1 billion of long-term variable interest rate exposure at December 31, 2017 was 2.3%. If the Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $11 million at December 31, 2017. See Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements for additional information.

To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and financial hedge contracts for natural gas purchases. The Company continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. The Company had no material change in market risk exposure for the year ended December 31, 2017 when compared to the year ended December 31, 2016.

In addition, Rate ECR allows the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at the Company's electric generating facilities. Rate ECR also allows recovery of the cost of financial instruments used for hedging market price risk up to 75% of the budgeted annual amount of natural gas purchases. The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. Also, the premiums paid for natural gas financial options may not exceed 5% of the Company's natural gas budget for that year.



	2017 Changes			2016 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	12		$	(54	)
Contracts realized or settled	(1		)	39
Current period changes^(*)	(17		)	27
Contracts outstanding at the end of the period, assets (liabilities), net	$	(6	)	$	12


(*)	Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

The net hedge volumes of energy-related derivative contracts, for the years ended December 31 were as follows:



	2017	2016
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	64	68
Commodity – Natural gas options	5	6
Total hedge volume	69	74

The weighted average swap contract cost above market prices was approximately $0.08 per mmBtu as of December 31, 2017 and below market prices was approximately $0.14 per mmBtu as of December 31, 2016. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. Substantially all of the natural gas hedge gains and losses are recovered through the Company's retail energy cost recovery clause.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

At December 31, 2017 and 2016, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or ~~return~~fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented.

The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 10 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are primarily Level 2 of the fair value hierarchy, at December 31, 2017 were as follows:



			Fair Value Measurements
			December 31, 2017
	Total		Maturity
	Fair Value		Year 1		Years 2&3
	(in millions)
Level 1	$	—	$	—	$	—
Level 2	6		4		2
Level 3	—		—		—
Fair value of contracts outstanding at end of period	$	6	$	4	$	2

The Company is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements.

Capital Requirements and Contractual Obligations

The construction program of the Company is currently estimated to total $2.2 billion for 2018, $1.6 billion for 2019, $1.6 billion for 2020, $1.7 billion for 2021, and $1.4 billion for 2022. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel ~~costs.~~and capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $581 million for 2018, $110 million for 2019, $163 million for 2020, $258 million for 2021, and $268 million for 2022. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO₂ emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and "– Global Climate Issues" herein for additional information.

The Company also anticipates costs associated with closure in place and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in the Company's ARO liabilities. These costs, which could change as the Company continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $0.3 million for 2018, $111 million for 2019, $90 million for 2020, $94 million for 2021, and $96 million for 2022. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information. Costs associated with the CCR Rule are expected to be recovered through Rate CNP Compliance.

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 the 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

As a result of NRC requirements, the Company has external trust funds for nuclear decommissioning costs; however, the Company currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under "Nuclear Decommissioning."

In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Alabama PSC and the FERC.

Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, pension and other postretirement benefit plans, preferred stock dividends, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 2, 6, 7, and 11 to the financial statements for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

Contractual Obligations

Contractual obligations at December 31, 2017 were as follows:



	2018		2019- 2020		2021- 2022		After 2022		Total
	(in millions)
Long-term debt^(a) —
Principal	$	—	$	450	$	1,060	$	6,176	$	7,686
Interest	304		598		561		4,408		5,871
Preferred stock dividends^(b)	15		29		29		—		73
Financial derivative obligations^(c)	6		4		—		—		10
Operating leases^(d)	21		40		24		20		105
Capital Lease	1		1		1		2		5
Purchase commitments —
Capital^(e)	2,053		2,972		2,914		—		7,939
Fuel^(f)	974		1,197		459		238		2,868
Purchased power^(g)	78		171		186		606		1,041
Other^(h)	47		73		59		313		492
Pension and other postretirement benefit plans⁽ⁱ⁾	19		36		—		—		55
Total	$	3,518	$	5,571	$	5,293	$	11,763	$	26,145

(a)

All amounts are reflected based on final maturity dates. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of December 31, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).


(b)	Preferred stock does not mature; therefore, amounts are provided for the next five years only.


(c)	Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, see Notes 1 and 11 to the financial statements.


(d)	Excludes PPAs that are accounted for as leases and are included in purchased power.

(e)

The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements which are reflected in "Fuel" and "Other," respectively. At December 31, 2017, purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" herein for additional information.

(f)

Includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2017.


(g)	Estimated minimum long-term obligations for various long-term commitments for the purchase of capacity and energy.


(h)	Includes long-term service agreements and contracts for the procurement of limestone. Long-term service agreements include price escalation based on inflation indices.

(i)

The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets.

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

The Company's 2017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plan, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, filings with state and federal regulatory authorities, impacts of the Tax Reform Legislation, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

current and future litigation or regulatory investigations, proceedings, or inquiries;

the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

variations in demand for electricity, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

available sources and costs of fuels;

effects of inflation;

the ability to control costs and avoid cost overruns during the development and construction of facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards;

investment performance of the Company's employee and retiree benefit plans and nuclear decommissioning trust funds;

advances in technology;

state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;

the inherent risks involved in operating nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;

the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;

internal restructuring or other restructuring options that may be pursued;

potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;

the ability of counterparties of the Company to make payments as and when due and to perform as required;

the ability to obtain new short- and long-term contracts with wholesale customers;

the direct or indirect effect on the Company's business resulting from cyber intrusion or physical attack and the threat of physical attacks;

interest rate fluctuations and financial market conditions and the results of financing efforts;

changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;

the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

the effect of accounting pronouncements issued periodically by standard-setting bodies; and

other factors discussed elsewhere herein and in other reports filed by the Company from time to time with the SEC.

The Company expressly disclaims any obligation to update any forward-looking statements.

Table of Contents Index to Financial Statements

STATEMENTS OF INCOME

For the Years Ended December 31, 2017, 2016, and 2015

Alabama Power Company 2017 Annual Report



	2017			2016			2015
	(in millions)
Operating Revenues:
Retail revenues	$	5,458		$	5,322		$	5,234
Wholesale revenues, non-affiliates	276			283			241
Wholesale revenues, affiliates	97			69			84
Other revenues	208			215			209
Total operating revenues	6,039			5,889			5,768
Operating Expenses:
Fuel	1,225			1,297			1,342
Purchased power, non-affiliates	170			166			171
Purchased power, affiliates	158			168			180
Other operations and maintenance	1,652			1,510			1,501
Depreciation and amortization	736			703			643
Taxes other than income taxes	384			380			368
Total operating expenses	4,325			4,224			4,205
Operating Income	1,714			1,665			1,563
Other Income and (Expense):
Allowance for equity funds used during construction	39			28			60
Interest expense, net of amounts capitalized	(305		)	(302		)	(274		)
Other income (expense), net	(14		)	(21		)	(32		)
Total other income and (expense)	(280		)	(295		)	(246		)
Earnings Before Income Taxes	1,434			1,370			1,317
Income taxes	568			531			506
Net Income	866			839			811
Dividends on Preferred and Preference Stock	18			17			26
Net Income After Dividends on Preferred and Preference Stock	$	848		$	822		$	785

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2017, 2016, and 2015

Alabama Power Company 2017 Annual Report



	2017		2016			2015
	(in millions)
Net Income	$	866	$	839		$	811
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1), $(1), and $(3), respectively	1		(2		)	(5		)
Reclassification adjustment for amounts included in net income, net of tax of $2, $2, and $1, respectively	3		4			2
Total other comprehensive income (loss)	4		2			(3		)
Comprehensive Income	$	870	$	841		$	808

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2017, 2016, and 2015

Alabama Power Company 2017 Annual Report



	2017			2016			2015
	(in millions)
Operating Activities:
Net income	$	866		$	839		$	811
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	888			844			780
Deferred income taxes	409			407			388
Allowance for equity funds used during construction	(39		)	(28		)	(60		)
Pension and postretirement funding	(2		)	(133		)	—
Other, net	(14		)	(102		)	15
Changes in certain current assets and liabilities —
-Receivables	(168		)	94			(160		)
-Other current assets	(16		)	1			40
-Accounts payable	71			73			3
-Accrued taxes	(84		)	93			138
-Retail fuel cost over recovery	(76		)	(162		)	191
-Other current liabilities	2			23			(4		)
Net cash provided from operating activities	1,837			1,949			2,142
Investing Activities:
Property additions	(1,882		)	(1,272		)	(1,367		)
Nuclear decommissioning trust fund purchases	(237		)	(352		)	(439		)
Nuclear decommissioning trust fund sales	237			351			438
Cost of removal net of salvage	(112		)	(94		)	(71		)
Change in construction payables	161			(37		)	(15		)
Other investing activities	(43		)	(34		)	(34		)
Net cash used for investing activities	(1,876		)	(1,438		)	(1,488		)
Financing Activities:
Increase in notes payable, net	3			—			—
Proceeds —
Senior notes	1,100			400			975
Preferred stock	250			—			—
Pollution control revenue bonds	—			—			80
Other long-term debt	—			45			—
Capital contributions from parent company	361			260			22
Redemptions and repurchases —
Senior notes	(525		)	(200		)	(650		)
Preferred and preference stock	(238		)	—			(412		)
Pollution control revenue bonds	(36		)	—			(134		)
Payment of common stock dividends	(714		)	(765		)	(571		)
Other financing activities	(38		)	(25		)	(43		)
Net cash provided from (used for) financing activities	163			(285		)	(733		)
Net Change in Cash and Cash Equivalents	124			226			(79		)
Cash and Cash Equivalents at Beginning of Year	420			194			273
Cash and Cash Equivalents at End of Year	$	544		$	420		$	194
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $15, $11, and $22 capitalized, respectively)	$	285		$	277		$	250
Income taxes (net of refunds)	236			(108		)	121
Noncash transactions — Accrued property additions at year-end	245			84			121

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS

At December 31, 2017 and 2016

Alabama Power Company 2017 Annual Report



Assets	2017			2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	544		$	420
Receivables —
Customer accounts receivable	355			348
Unbilled revenues	162			146
Affiliated	43			40
Other accounts and notes receivable	55			27
Accumulated provision for uncollectible accounts	(9		)	(10		)
Fossil fuel stock	184			205
Materials and supplies	458			435
Other regulatory assets, current	124			149
Other current assets	90			45
Total current assets	2,006			1,805
Property, Plant, and Equipment:
In service	27,326			26,031
Less: Accumulated provision for depreciation	9,563			9,112
Plant in service, net of depreciation	17,763			16,919
Nuclear fuel, at amortized cost	339			336
Construction work in progress	908			491
Total property, plant, and equipment	19,010			17,746
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	67			66
Nuclear decommissioning trusts, at fair value	903			792
Miscellaneous property and investments	124			112
Total other property and investments	1,094			970
Deferred Charges and Other Assets:
Deferred charges related to income taxes	239			525
Deferred under recovered regulatory clause revenues	54			150
Other regulatory assets, deferred	1,272			1,157
Other deferred charges and assets	189			163
Total deferred charges and other assets	1,754			1,995
Total Assets	$	23,864		$	22,516

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS

At December 31, 2017 and 2016

Alabama Power Company 2017 Annual Report



Liabilities and Stockholder's Equity	2017		2016
	(in millions)
Current Liabilities:
Securities due within one year	$	—	$	561
Accounts payable —
Affiliated	327		297
Other	585		433
Customer deposits	92		88
Accrued taxes —
Accrued income taxes	9		45
Other accrued taxes	45		42
Accrued interest	77		78
Accrued compensation	205		193
Other regulatory liabilities, current	1		85
Other current liabilities	59		76
Total current liabilities	1,400		1,898
Long-Term Debt (See accompanying statements)	7,628		6,535
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	2,760		4,654
Deferred credits related to income taxes	2,082		65
Accumulated deferred ITCs	112		110
Employee benefit obligations	304		300
Asset retirement obligations	1,702		1,503
Other cost of removal obligations	609		684
Other regulatory liabilities, deferred	84		100
Other deferred credits and liabilities	63		63
Total deferred credits and other liabilities	7,716		7,479
Total Liabilities	16,744		15,912
Redeemable Preferred Stock (See accompanying statements)	291		85
Preference Stock (See accompanying statements)	—		196
Common Stockholder's Equity (See accompanying statements)	6,829		6,323
Total Liabilities and Stockholder's Equity	$	23,864	$	22,516
Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CAPITALIZATION

At December 31, 2017 and 2016

Alabama Power Company 2017 Annual Report



	2017			2016			2017		2016
	(in millions)						(percent of total)
Long-Term Debt:
Long-term debt payable to affiliated trusts —
Variable rate (4.44% at 12/31/17) due 2042	$	206		$	206
Long-term notes payable —
5.50% to 5.55% due 2017	—			525
5.125% due 2019	200			200
3.375% due 2020	250			250
2.38% to 3.95% due 2021	220			220
2.45% to 5.875% due 2022	750			200
2.80% to 6.125% due 2023-2047	4,975			4,425
Variable rates (2.55% to 2.786% at 12/31/17) due 2021	25			25
Total long-term notes payable	6,420			5,845
Other long-term debt —
Pollution control revenue bonds —
1.625% to 1.85% due 2034	207			207
Variable rates (0.77% to 0.79% at 1/1/17) due 2017	—			36
Variable rates (1.86% to 1.87% at 12/31/17) due 2021	65			65
Variable rates (1.70% to 1.87% at 12/31/17) due 2024-2038	788			788
Total other long-term debt	1,060			1,096
Capitalized lease obligations	4			4
Unamortized debt premium (discount), net	(11		)	(9		)
Unamortized debt issuance expense	(51		)	(46		)
Total long-term debt (annual interest requirement — $305 million)	7,628			7,096
Less amount due within one year	—			561
Long-term debt excluding amount due within one year	7,628			6,535			51.7	%	49.7	%
Redeemable Preferred Stock:
Cumulative redeemable preferred stock
$100 par or stated value — 4.20% to 4.92%
Authorized — 3,850,000 shares
Outstanding — 475,115 shares	48			48
$1 par value —
Authorized — 27,500,000 shares
Outstanding — 2017: 5.00% — 10,000,000 shares: $25 stated value
— 2016: 5.83% — 1,520,000 shares: $25 stated value
(annual dividend requirement — $15 million)	243			37
Total redeemable preferred stock	291			85			2.0		0.7
Preference Stock:
$1 par value — 6.45% to 6.50%
Authorized — 40,000,000 shares
Outstanding — 2017: no shares
— 2016: 8,000,000 shares (non-cumulative): $25 stated value	—			196			—		1.5
Common Stockholder's Equity:
Common stock, par value $40 per share —
Authorized — 40,000,000 shares
Outstanding — 30,537,500 shares	1,222			1,222
Paid-in capital	2,986			2,613
Retained earnings	2,647			2,518
Accumulated other comprehensive loss	(26		)	(30		)
Total common stockholder's equity	6,829			6,323			46.3		48.1
Total Capitalization	$	14,748		$	13,139		100.0	%	100.0	%

The accompanying notes are an integral part of these financial statements.

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Rate NDR

Table of Contents Index to Financial Statements

NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Environmental Accounting Order

Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. The regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance.

Georgia Power

Rate Plans

Under the 2013 ARP, Georgia Power's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2015, Georgia Power's retail ROE was within the allowed retail ROE range. In 2016, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power will refund to retail customers approximately $44 million in 2018, as approved by the Georgia PSC on January 16, 2018. In 2017, Georgia Power's retail ROE was within the allowed retail ROE range, subject to review and approval by the Georgia PSC.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

On January 19, 2018, the Georgia PSC issued an order on the Tax Reform Legislation, which was amended on February 16, 2018 (Tax Order). In accordance with the Tax Order, Georgia Power is required to submit its analysis of the Tax Reform Legislation and related recommendations to address the related impacts on Georgia Power's cost of service and annual revenue requirements by March 6, 2018. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plan

Fuel Cost Recovery

Storm Damage Recovery

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Gulf Power

Retail Base Rate Cases

In 2013, the Florida PSC approved a settlement agreement related to Gulf Power's 2013 retail base rate case that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction was not to exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. In 2017, Gulf Power recognized the remaining $34.0 million reduction in depreciation.

On April 4, 2017, the Florida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three intervenors with respect to Gulf Power's request in 2016 to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes. Gulf Power also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause.

The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to Gulf Power's base rates. Under the terms of the 2017 Rate Case Settlement Agreement, by March 1, 2018, Gulf Power must identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to Gulf Power's base rates and $15.6 million to Gulf Power's environmental cost recovery rates effective beginning the first calendar month following approval.

The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through Gulf Power's fuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and Gulf Power will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.

The ultimate outcome of these matters cannot be determined at this time.

Mississippi Power

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

performance adjusted ROE of 9.33% and an increased equity ratio of 55%. The ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. Atlanta Gas Light earns revenue for its distribution services by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically.

With the exception of Atlanta Gas Light, 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 and energy efficiency plans. See Note 1 under "Cost of Natural Gas" for additional information.

Regulatory Infrastructure Programs

Certain of Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs are 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. Initial program lengths range from nine to 10 years, with completion dates ranging from 2020 through 2025.

Base Rate Cases

The Illinois Commerce Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commerce Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which Nicor Gas expects to file by the end of the second quarter 2018.

The ultimate outcome of these matters cannot be determined at this time.

Kemper County Energy Facility

Overview

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

commercial operation in 2013. In connection with the Kemper County energy facility construction, Mississippi Power constructed approximately 61 miles of CO₂ pipeline infrastructure for the transport of captured CO₂ for use in enhanced oil recovery.

Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper County energy facility. The certificated cost estimate of the Kemper County energy facility included in the 2012 MPSC CPCN Order was $2.4 billion, net of approximately $0.57 billion for the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions (Cost Cap Exceptions). The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper County energy facility was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper County energy facility in service in August 2014.

The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO₂, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast had decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations had increased significantly since certification.

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of the related costs (Kemper Settlement Docket). On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement).

At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE for the Kemper County energy facility. In the aggregate, Mississippi Power had recorded charges to income of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017.

Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power has begun efforts to dispose of or abandon the mine and gasifier-related assets.

Rate Recovery

Kemper Settlement Agreement

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).

As of December 31, 2017, the balances associated with the Kemper County energy facility regulatory assets and liabilities were $114 million and $26 million, respectively.

As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.

2015 Rate Case

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order regarding the Kemper County energy facility assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets.

In connection with the implementation of the In-Service Asset Rate Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees over periods ranging from two years to 10 years. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper County energy facility following the July 2017 completion of the amortization period for certain of these regulatory assets.

Lignite Mine and CO₂ Pipeline Facilities

Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. The mine started commercial operation in June 2013.

In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. Mississippi Power expects mine reclamation to begin in 2018. In addition to the obligation to fund the reclamation activities, Mississippi Power provided working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.

In addition, Mississippi Power constructed the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery and entered into an agreement with Denbury Onshore (Denbury) to purchase the captured CO₂. Denbury has the right to terminate the contract at any time because Mississippi Power did not place the Kemper IGCC in service by July 1, 2017.

The ultimate outcome of these matters cannot be determined at this time.

Litigation

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

On June 9, 2016, Treetop, Greenleaf CO₂ Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint related to the cancelled CO₂ contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and sought compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO₂ contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages. On December 28, 2017, Mississippi Power reached a settlement agreement with Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group and the arbitration was dismissed.

Nuclear Construction

Project Status

In 2009, the Georgia PSC certified construction of 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. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

Georgia Power expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. Georgia Power's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under the Guarantee Settlement Agreement and the Customer Refunds, each as defined herein). Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.

Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy

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Southern Company and Subsidiary Companies 2017 Annual Report

On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, 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 (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power 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 because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. 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.

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Southern Company and Subsidiary Companies 2017 Annual Report

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 nuclear construction projects certified by the Georgia PSC. 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. As of December 31, 2017, Georgia Power had recovered approximately $1.6 billion of financing costs. On January 30, 2018, Georgia Power filed to decrease the NCCR tariff by approximately $50 million, effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, refunds to customers ordered by the Georgia PSC aggregating approximately $188 million (Customer Refunds), and the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and will be paid in three installments of $25 to each retail customer no later than the third quarter 2018.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. Georgia Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of operations, financial condition, and liquidity.

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Southern Company and Subsidiary Companies 2017 Annual Report

The ultimate outcome of these matters cannot be determined at this time.

Cost and Schedule



	(in billions)
Project capital cost forecast	$	7.3
Net investment as of December 31, 2017	(3.4		)
Remaining estimate to complete	$	3.9

Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.

The ultimate outcome of these matters cannot be determined at this time.

Other Matters

As of December 31, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

The ultimate outcome of these matters cannot be determined at this time.

Other Matters

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Southern Company and Subsidiary Companies 2017 Annual Report

The cavern continues to maintain its pressures and overall structural integrity. These events were considered in connection with Southern Company Gas' annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements.

4. JOINT OWNERSHIP AGREEMENTS

Alabama Power owns an undivided interest in Units 1 and 2 at Plant Miller and related facilities jointly with PowerSouth Energy Cooperative, Inc. Georgia Power owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: Oglethorpe Power Corporation (OPC), MEAG Power, the City of Dalton, Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities, Florida Power & Light Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities. In August 2016, Georgia Power sold its 33% ownership interest in the Intercession City combustion turbine unit to Duke Energy Florida, LLC. Southern Power owns an undivided interest in Plant Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency. Southern Company Gas has a 50% undivided ownership interest in the Dalton Pipeline jointly with The Williams Companies, Inc.

At December 31, 2017, Alabama Power's, Georgia Power's, Southern Power's, and Southern Company Gas' percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows:



Facility (Type)	Percent Ownership		Plant in Service		Accumulated Depreciation		CWIP
			(in millions)
Plant Vogtle (nuclear) Units 1 and 2	45.7	%	$	3,564	$	2,141	$	70
Plant Hatch (nuclear)	50.1		1,321		595		87
Plant Miller (coal) Units 1 and 2	91.8		1,717		619		54
Plant Scherer (coal) Units 1 and 2	8.4		261		93		8
Plant Wansley (coal)	53.5		1,053		335		72
Rocky Mountain (pumped storage)	25.4		182		132		—
Plant Stanton (combined cycle) Unit A	65.0		155		55		—
Dalton Pipeline (natural gas pipeline)	50.0		241		2		13

Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4, which are currently under construction and had a CWIP balance of $3.3 billion as of December 31, 2017. See Note 3 under "Nuclear Construction" for additional information.

Alabama Power and Georgia Power have contracted to operate and maintain their jointly-owned facilities, except for Rocky Mountain, as agents for their respective co-owners. Southern Power has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton Unit A. The companies' proportionate share of their plant operating expenses is included in the corresponding operating expenses in the statements of income and each company is responsible for providing its own financing.

Southern Company Gas entered into an agreement to lease its 50% undivided ownership in the Dalton Pipeline that became effective when it was placed in service on August 1, 2017. Under the lease, Southern Company Gas will receive approximately $26 million annually for an initial term of 25 years. The lessee is responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff.

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Southern Company and Subsidiary Companies 2017 Annual Report

5. INCOME TAXES

Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. PowerSecure and Southern Company Gas became participants in the income tax allocation agreement as of May 9, 2016 and July 1, 2016, respectively. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.

Federal Tax Reform Legislation

Current and Deferred Income Taxes

Details of income tax provisions are as follows:



	2017			2016			2015
	(in millions)
Federal —
Current	$	(62	)	$	1,184		$	(177	)
Deferred	(6		)	(342		)	1,266
	(68		)	842			1,089
State —
Current	37			(108		)	(33		)
Deferred	173			217			138
	210			109			105
Total	$	142		$	951		$	1,194

Net cash payments (refunds) for income taxes in 2017, 2016, and 2015 were $(410) million, $(148) million, and $(9) million, respectively.

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Southern Company and Subsidiary Companies 2017 Annual Report



	2017			2016
	(in millions)
Deferred tax liabilities —
Accelerated depreciation	$	10,267		$	15,392
Property basis differences	955			2,708
Leveraged lease basis differences	251			314
Employee benefit obligations	516			737
Premium on reacquired debt	54			89
Regulatory assets associated with employee benefit obligations	1,046			1,584
Regulatory assets associated with AROs	1,225			1,781
Other	697			907
Total	15,011			23,512
Deferred tax assets —
Federal effect of state deferred taxes	326			597
Employee benefit obligations	1,307			1,868
Over recovered fuel clause	—			66
Other property basis differences	446			401
Deferred costs	69			100
ITC carryforward	2,420			1,974
Federal NOL carryforward	518			1,084
Unbilled revenue	57			92
Other comprehensive losses	84			152
AROs	1,197			1,732
Estimated Loss on Kemper IGCC	722			484
Deferred state tax assets	328			266
Regulatory liability associated with the Tax Reform Legislation (not subject to normalization)	465			—
Other	485			679
Total	8,424			9,495
Valuation allowance	(149		)	(23		)
Total deferred income taxes	6,736			14,040
Portion included in accumulated deferred tax assets	(106		)	(52		)
Accumulated deferred income taxes	$	6,842		$	14,092

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Southern Company and Subsidiary Companies 2017 Annual Report

Tax Credit Carryforwards

Additionally, Southern Company had state ITC carryforwards for the state of Georgia totaling approximately $318 million, which will expire between 2020 and 2027 but are expected to be fully utilized.

Net Operating Loss

At December 31, 2017, the state NOL carryforwards for Southern Company's subsidiaries were as follows:



Jurisdiction	Approximate NOL Carryforwards		Approximate Net State Income Tax Benefit		Tax Year NOL Begins Expiring
	(in millions)
Mississippi	$	2,890	$	114	2032
Oklahoma	986		47		2036
Georgia	524		23		2019
New York	229		13		2036
New York City	209		15		2036
Florida	304		13		2034
Other states	465		24		Various
Total	$	5,607	$	249

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Southern Company and Subsidiary Companies 2017 Annual Report

Effective Tax Rate

A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:



	2017		2016		2015
Federal statutory rate	35.0	%	35.0	%	35.0	%
State income tax, net of federal deduction	12.5		2.1		1.9
Employee stock plans dividend deduction	(4.1	)	(1.2	)	(1.2	)
Non-deductible book depreciation	3.1		0.9		1.2
AFUDC-Equity	(2.6	)	(2.0	)	(2.2	)
Non-deductible equity portion on Kemper IGCC write-off	15.7		—		—
ITC basis difference	(1.7	)	(5.0	)	(1.5	)
Federal PTCs	(12.1	)	(1.2	)	—
Amortization of ITC	(4.2	)	(0.9	)	(0.5	)
Tax Reform Legislation	(25.6	)	—		—
Other	(2.7	)	(0.4	)	0.2
Effective income tax rate	13.3	%	27.3	%	32.9	%

Legal Entity Reorganization

In September 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization included the purchase of all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $55 million related to certain changes in state apportionment rates and net operating loss carryforward utilization that will be recorded in the first quarter 2018. The ultimate outcome of this matter cannot be determined at this time.

Unrecognized Tax Benefits

Changes during the year in unrecognized tax benefits were as follows:



	2017			2016			2015
	(in millions)
Unrecognized tax benefits at beginning of year	$	484		$	433		$	170
Tax positions increase from current periods	10			45			43
Tax positions increase from prior periods	10			21			240
Tax positions decrease from prior periods	(196		)	(15		)	(20		)
Reductions due to settlements	(290		)	—			—
Balance at end of year	$	18		$	484		$	433

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

The impact on Southern Company's effective tax rate, if recognized, is as follows:



	2017		2016		2015
	(in millions)
Tax positions impacting the effective tax rate	$	18	$	20	$	10
Tax positions not impacting the effective tax rate	—		464		423
Balance of unrecognized tax benefits	$	18	$	484	$	433

Accrued interest for all tax positions other than the Section 174 R&E deductions was immaterial for all years presented.

Southern Company classifies interest on tax uncertainties as interest expense. Southern Company did not accrue any penalties on uncertain tax positions.

Section 174 Research and Experimental Deduction

6. FINANCING

Securities Due Within One Year

A summary of scheduled maturities of securities due within one year at December 31 was as follows:



	2017			2016
	(in millions)
Senior notes	$	2,354		$	1,995
Other long-term debt	1,420			485
Revenue bonds^(*)	90			76
Capitalized leases	31			32
Unamortized debt issuance expense/discount	(3		)	(1		)
Total	$	3,892		$	2,587


(*)	Includes $50 million in revenue bonds classified as short term at December 31, 2017 that were remarketed in an index rate mode subsequent to December 31, 2017. Also includes $40 million in pollution control revenue bonds classified as short term since they are variable rate demand obligations supported by short-term credit facilities; however, the final maturity dates range from 2020 to 2028.

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Southern Company and Subsidiary Companies 2017 Annual Report

Maturities through 2022 applicable to total long-term debt are as follows: $3.9 billion in 2018; $3.2 billion in 2019; $3.2 billion in 2020; $3.1 billion in 2021; and $2.2 billion in 2022.

Bank Term Loans

At December 31, 2017, Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $450 million, $45 million, $250 million, $900 million, and $420 million, respectively, of which $1.5 billion are reflected in the statements of capitalization as long-term debt and $600 million are reflected in the balance sheet as notes payable. At December 31, 2016, Southern Company, Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $400 million, $45 million, $100 million, $1.2 billion, and $380 million, respectively, of which $2.0 billion were reflected in the statements of capitalization as long-term debt and $100 million were reflected in the balance sheet as notes payable.

In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.

DOE Loan Guarantee Borrowings

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

At both December 31, 2017 and 2016, Georgia Power had $2.6 billion of borrowings outstanding under the FFB Credit Facility.

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Southern Company and Subsidiary Companies 2017 Annual Report

Senior Notes

Since Southern Company is a holding company, the right of Southern Company and, hence, the right of creditors of Southern Company (including holders of Southern Company senior notes) to participate in any distribution of the assets of any subsidiary of Southern Company, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred stockholders of such subsidiary.

Junior Subordinated Notes

At December 31, 2017 and 2016, Southern Company and its subsidiaries had a total of $3.6 billion and $2.4 billion, respectively, of junior subordinated notes outstanding.

Pollution Control Revenue Bonds

Plant Daniel Revenue Bonds

Gas Facility Revenue Bonds

Pivotal Utility Holdings, Inc., a subsidiary of Southern Company Gas (Pivotal Utility Holdings), is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued with maturities ranging from 2022 to 2033. These revenue bonds are issued by state

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Southern Company and Subsidiary Companies 2017 Annual Report

Other Revenue Bonds

First Mortgage Bonds

Long-Term Debt Payable to an Affiliated Trust

Capital Leases

Assets acquired under capital leases are recorded in the balance sheets as property, plant, and equipment and the related obligations are classified as long-term debt.

Assets Subject to Lien

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

The first mortgage bonds issued by Nicor Gas are secured by substantially all of Nicor Gas' properties. See "First Mortgage Bonds" herein for additional information.

Bank Credit Arrangements

At December 31, 2017, committed credit arrangements with banks were as follows:



	Expires												Executable Term Loans				Expires Within One Year
Company	2018		2019		2020		2022		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)
Southern Company^(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—	$	—	$	—	$	—
Alabama Power	35		—		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	30		25		225		—		280		280		45		—		20		10
Mississippi Power	100		—		—		—		100		100		—		—		—		100
Southern Power Company^(b)	—		—		—		750		750		728		—		—		—		—
Southern Company Gas^(c)	—		—		—		1,900		1,900		1,890		—		—		—		—
Other	30		—		—		—		30		30		20		—		20		10
Southern Company Consolidated	$	195	$	25	$	725	$	7,200	$	8,145	$	8,094	$	65	$	—	$	40	$	155


(a)	Represents the Southern Company parent entity.


(b)	Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $19 million remains unused at December 31, 2017.


(c)	Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

Most of the bank credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than ¹/4 of 1% for Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. Compensating balances are not legally restricted from withdrawal.

Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets.

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Southern Company and Subsidiary Companies 2017 Annual Report

Details of short-term borrowings were as follows:



	Short-term Debt at the End of the Period
	Amount Outstanding		Weighted Average Interest Rate
	(in millions)
December 31, 2017:
Commercial paper	$	1,832	1.8	%
Short-term bank debt	607		2.3	%
Total	$	2,439	1.9	%
December 31, 2016:
Commercial paper	$	1,909	1.1	%
Short-term bank debt	123		1.7	%
Total	$	2,032	1.1	%

Redeemable Preferred Stock of Subsidiaries

The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company:



	Redeemable Preferred Stock of Subsidiaries
	(in millions)
Balance at December 31, 2014	$	375
Issued	—
Redeemed	(262		)
Issuance costs	5
Balance at December 31, 2015:	118
Issued	—
Redeemed	—
Balance at December 31, 2016:	118
Issued	250
Redeemed	(38		)
Issuance costs	(6		)
Balance at December 31, 2017:	$	324

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Southern Company and Subsidiary Companies 2017 Annual Report

7. COMMITMENTS

Fuel and Purchased Power Agreements

Estimated total obligations under these commitments at December 31, 2017 were as follows:



	Operating Leases		Other
	(in millions)
2018	$	247	$	7
2019	250		6
2020	247		4
2021	249		5
2022	252		4
2023 and thereafter	806		38
Total	$	2,051	$	64

Pipeline Charges, Storage Capacity, and Gas Supply

Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2017 were as follows:



	Pipeline Charges, Storage Capacity, and Gas Supply
	(in millions)
2018	$	813
2019	552
2020	416
2021	375
2022	339
2023 and thereafter	2,294
Total	$	4,789

Operating Leases

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Southern Company and Subsidiary Companies 2017 Annual Report

As of December 31, 2017, estimated minimum lease payments under operating leases were as follows:



	Minimum Lease Payments
	Barges & Railcars		Other^(*)		Total
	(in millions)
2018	$	21	$	128	$	149
2019	11		113		124
2020	9		99		108
2021	8		87		95
2022	6		77		83
2023 and thereafter	5		963		968
Total	$	60	$	1,467	$	1,527


(*)	Includes operating leases for cellular tower space, facilities, vehicles, and other equipment.

For the traditional electric operating companies, a majority of the barge and railcar lease expenses are recoverable through fuel cost recovery provisions.

Guarantees

As discussed above under "Operating Leases," Alabama Power and Georgia Power have entered into certain residual value guarantees.

8. COMMON STOCK

Stock Issued

During 2017, Southern Company issued approximately 14.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $659 million.

Shares Reserved

Stock-Based Compensation

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Southern Company and Subsidiary Companies 2017 Annual Report

Performance Share Units



Year Ended December 31	2017	2016	2015
Expected volatility	15.6%	15.0%	12.9%
Expected term (in years)	3	3	3
Interest rate	1.4%	0.8%	1.0%
Weighted average grant-date fair value	$49.08	$45.06	$46.38

The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017, 2016, and 2015 was $49.21, $48.87, and $47.75, respectively.

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Southern Company and Subsidiary Companies 2017 Annual Report

Restricted Stock Units

The weighted average grant-date fair value of restricted stock units granted during 2017 was $49.25.

Stock Options

Southern Company's activity in the stock option program for 2017 is summarized below:



	Shares Subject to Option	Weighted Average Exercise Price
	(in millions)
Outstanding at December 31, 2016	24.6	$	41.28
Exercised	6.0	40.03
Cancelled	—	39.90
Outstanding and Exercisable at December 31, 2017	18.6	$	41.68

Total compensation cost for stock option awards and the related tax benefits recognized in income were immaterial for all years presented.

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Southern Company and Subsidiary Companies 2017 Annual Report

Southern Company Gas Restricted Stock Awards

Southern Company Gas Change in Control Awards

Diluted Earnings Per Share



	Average Common Stock Shares
	2017	2016	2015
	(in millions)
As reported shares	1,000	951	910
Effect of options and performance share award units	8	7	4
Diluted shares	1,008	958	914

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

performance share award units that were not included in the diluted EPS calculation because they were anti-dilutive were immaterial in all years presented.

Common Stock Dividend Restrictions

9. NUCLEAR INSURANCE

For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the applicable company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by Alabama Power or Georgia Power, as applicable, and could have a material effect on Southern Company's financial condition and results of operations.

All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.

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Southern Company and Subsidiary Companies 2017 Annual Report

10. FAIR VALUE MEASUREMENTS

Level 1 consists of observable market data in an active market for identical assets or liabilities.

Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.

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Southern Company and Subsidiary Companies 2017 Annual Report

As of December 31, 2017, 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
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient
As of December 31, 2017:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Energy-related derivatives^(a)(b)	$	331	$	239	$	—	$	—	$	570
Interest rate derivatives	—		1		—		—		1
Foreign currency derivatives	—		129		—		—		129
Nuclear decommissioning trusts:^(c)
Domestic equity	690		82		—		—		772
Foreign equity	62		224		—		—		286
U.S. Treasury and government agency securities	—		251		—		—		251
Municipal bonds	—		68		—		—		68
Corporate bonds	21		315		—		—		336
Mortgage and asset backed securities	—		57		—		—		57
Private equity	—		—		—		29		29
Other	19		12		—		—		31
Cash equivalents	1,455		—		—		—		1,455
Other investments	9		—		1		—		10
Total	$	2,587	$	1,378	$	1	$	29	$	3,995
Liabilities:
Energy-related derivatives^(a)(b)	$	480	$	253	$	—	$	—	$	733
Interest rate derivatives	—		38		—		—		38
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		22		—		22
Total	$	480	$	314	$	22	$	—	$	816


(a)	Energy-related derivatives exclude $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.


(b)	Energy-related derivatives exclude cash collateral of $193 million.


(c)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. See Note 1 under "Nuclear Decommissioning" for additional information.

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Southern Company and Subsidiary Companies 2017 Annual Report

As of December 31, 2016, 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
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Net Asset Value as a Practical Expedient
As of December 31, 2016:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Assets:
Energy-related derivatives^(a)(b)	$	338	$	333	$	—	$	—	$	671
Interest rate derivatives	—		14		—		—		14
Nuclear decommissioning trusts:^(c)
Domestic equity	589		73		—		—		662
Foreign equity	48		168		—		—		216
U.S. Treasury and government agency securities	—		92		—		—		92
Municipal bonds	—		73		—		—		73
Corporate bonds	22		310		—		—		332
Mortgage and asset backed securities	—		183		—		—		183
Private equity	—		—		—		20		20
Other	11		15		—		—		26
Cash equivalents	1,172		—		—		—		1,172
Other investments	9		—		1		—		10
Total	$	2,189	$	1,261	$	1	$	20	$	3,471
Liabilities:
Energy-related derivatives^(a)(b)	$	345	$	285	$	—	$	—	$	630
Interest rate derivatives	—		29		—		—		29
Foreign currency derivatives	—		58		—		—		58
Contingent consideration	—		—		18		—		18
Total	$	345	$	372	$	18	$	—	$	735


(a)	Energy-related derivatives exclude $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.


(b)	Energy-related derivatives exclude cash collateral of $62 million.


(c)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. See Note 1 under "Nuclear Decommissioning" for additional information.

Valuation Methodologies

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Southern Company and Subsidiary Companies 2017 Annual Report



	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
As of December 31, 2017	$	29	$	21	Not Applicable	Not Applicable
As of December 31, 2016	$	20	$	25	Not Applicable	Not Applicable

As of December 31, 2017 and 2016, other financial instruments for which the carrying amount did not equal fair value were as follows:



	Carrying Amount		Fair Value
	(in millions)
Long-term debt, including securities due within one year:
2017	$	48,151	$	51,348
2016	$	45,080	$	46,286

11. DERIVATIVES

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Southern Company and Subsidiary Companies 2017 Annual Report

Energy-Related Derivatives

Energy-related derivative contracts are accounted for under one of three methods:

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.

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Southern Company and Subsidiary Companies 2017 Annual Report

Interest Rate Derivatives

At December 31, 2017, the following interest rate derivatives were outstanding:



	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) December 31, 2017
	(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
	$	900	1-month LIBOR	0.79%	March 2018	$	1
Fair Value Hedges of Existing Debt
	250		5.40%	3-month LIBOR + 4.02%	June 2018	—
	500		1.95%	3-month LIBOR + 0.76%	December 2018	(3		)
	200		4.25%	3-month LIBOR + 2.46%	December 2019	(1		)
	300		2.75%	3-month LIBOR + 0.92%	June 2020	(2		)
	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	(31		)
Total	$	3,650				$	(36	)

Foreign Currency Derivatives

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Southern Company and Subsidiary Companies 2017 Annual Report

At December 31, 2017, the following foreign currency derivatives were outstanding:



	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at December 31, 2017
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
	$	677	2.95%	€	600	1.00%	June 2022	$	55
	564		3.78%	500		1.85%	June 2026	51
Total	$	1,241		€	1,100			$	106

Derivative Financial Statement Presentation and Amounts

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Southern Company and Subsidiary Companies 2017 Annual Report

At December 31, 2017 and 2016, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:



	2017						2016
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	10		$	43		$	73		$	27
Other deferred charges and assets/Other deferred credits and liabilities	7			24			25			33
Total derivatives designated as hedging instruments for regulatory purposes	$	17		$	67		$	98		$	60
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	3		$	14		$	23		$	7
Interest rate derivatives:
Other current assets/Other current liabilities	1			4			12			1
Other deferred charges and assets/Other deferred credits and liabilities	—			34			1			28
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			25
Other deferred charges and assets/Other deferred credits and liabilities	129			—			—			33
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	133		$	75		$	36		$	94
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	380		$	437		$	489		$	483
Other deferred charges and assets/Other deferred credits and liabilities	170			215			66			81
Interest rate derivatives:
Other current assets/Other current liabilities	—			—			1			—
Total derivatives not designated as hedging instruments	$	550		$	652		$	556		$	564
Gross amounts recognized	$	700		$	794		$	690		$	718
Gross amounts offset^(a)	$	(405	)	$	(598	)	$	(462	)	$	(524	)
Net amounts recognized in the Balance Sheets^(b)	$	295		$	196		$	228		$	194


(a)	Gross amounts offset include cash collateral held on deposit in broker margin accounts of $193 million and $62 million as of December 31, 2017 and 2016, respectively.


(b)	Net amounts of derivative instruments outstanding exclude premiums and intrinsic value associated with weather derivatives of $11 million as of December 31, 2017.

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Southern Company and Subsidiary Companies 2017 Annual Report



	Unrealized Losses							Unrealized Gains
Derivative Category	Balance Sheet Location	2017			2016			Balance Sheet Location	2017		2016
		(in millions)							(in millions)
Energy-related derivatives:	Other regulatory assets, current	$	(34	)	$	(16	)	Other regulatory liabilities, current	$	7	$	56
	Other regulatory assets, deferred	(18		)	(19		)	Other regulatory liabilities, deferred	1		12
Total energy-related derivative gains (losses)^(*)		$	(52	)	$	(35	)		$	8	$	68


(*)	Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million and $8 million as of December 31, 2017 and 2016, respectively.



Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)									Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
	Amount										Amount
Derivative Category	2017			2016			2015			Statements of Income Location	2017			2016			2015
	(in millions)										(in millions)
Energy-related derivatives	$	(47	)	$	18		$	—		Depreciation and amortization	$	(16	)	$	2		$	—
										Cost of natural gas	(2		)	(1		)	—
Interest rate derivatives	(2		)	(180		)	(22		)	Interest expense, net of amounts capitalized	(21		)	(18		)	(9		)
Foreign currency derivatives	140			(58		)	—			Interest expense, net of amounts capitalized	(23		)	(13		)	—
										Other income (expense), net^(*)	160			(82		)	—
Total	$	91		$	(220	)	$	(22	)		$	98		$	(112	)	$	(9	)


(*)	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 euro-denominated notes.

There was no material ineffectiveness recorded in earnings for any period presented.

For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:



Derivatives in Fair Value Hedging Relationships		Gain (Loss)
Derivative Category	Statements of Income Location	2017			2016			2015
		(in millions)
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	(22	)	$	(21	)	$	2

For all years presented, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.

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Southern Company and Subsidiary Companies 2017 Annual Report

For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:



Derivatives Not Designated as Hedging Instruments		Unrealized Gain (Loss) Recognized in Income
		Amount
Derivative Category	Statements of Income Location	2017			2016		2015
		(in millions)
Energy-related derivatives	Wholesale electric revenues	$	(4	)	$	2	$	(5	)
	Fuel	—			—		3
	Natural gas revenues^(*)	(80		)	33		—
	Cost of natural gas	(2		)	3		—
Total		$	(86	)	$	38	$	(2	)


(*)	Excludes gains (losses) recorded in natural gas revenues associated with weather derivatives of $23 million and $6 million for the years ended December 31, 2017 and 2016, respectively.

For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of interest rate derivatives not designated as hedging instruments were immaterial.

Contingent Features

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Southern Company and Subsidiary Companies 2017 Annual Report

Southern Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

12. ACQUISITIONS AND DISPOSITIONS

Southern Company

Merger with Southern Company Gas



Southern Company Gas Purchase Price
	(in millions)
Current assets	$	1,557
Property, plant, and equipment	10,108
Goodwill	5,967
Intangible assets	400
Regulatory assets	1,118
Other assets	229
Current liabilities	(2,201		)
Other liabilities	(4,742		)
Long-term debt	(4,261		)
Noncontrolling interest	(174		)
Total purchase price	$	8,001

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Southern Company and Subsidiary Companies 2017 Annual Report



	2016		2015

Operating revenues (in millions)	$	21,791	$	21,430
Net income attributable to Southern Company (in millions)	$	2,591	$	2,665
Basic EPS	$	2.70	$	2.85
Diluted EPS	$	2.68	$	2.84

Acquisition of PowerSecure



PowerSecure Purchase Price
	(in millions)
Current assets	$	172
Property, plant, and equipment	46
Intangible assets	106
Goodwill	284
Other assets	4
Current liabilities	(121		)
Long-term debt, including current portion	(48		)
Deferred credits and other liabilities	(14		)
Total purchase price	$	429

Southern Power

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The following table presents Southern Power's acquisition activity for the year ended, and subsequent to, December 31, 2017.



Project Facility	Resource	Seller; Acquisition Date	Approximate Nameplate Capacity (MW)	Location	Southern Power Percentage Ownership			Actual/Expected COD	PPA Contract Period
Business Acquisitions During the Year Ended December 31, 2017
Bethel	Wind	Invenergy Wind Global LLC, January 6, 2017	276	Castro County, TX	100	%		January 2017	12 years
Cactus Flats^(a)	Wind	RES America Developments, Inc. July 31, 2017	148	Concho County, TX	100	%		Third quarter 2018	12 years and 15 years
Business Acquisitions Subsequent to December 31, 2017
Gaskell West 1	Solar	Recurrent Energy Development Holdings, LLC, January 26, 2018	20	Kern County, CA	100% of Class B		(b)	March 2018	20 years


(a)	On July 31, 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. Upon placing the facility in service, Southern Power expects to close on a tax equity partnership agreement that has already been executed, subject to various customary conditions at closing, and will then own 100% of the class B membership interests.


(b)	Southern Power owns 100% of the class B membership interest under a tax equity partnership agreement.

Business Acquisitions During the Year Ended December 31, 2017



	2017
	(in millions)
Restricted cash	$	16
CWIP	534
Other assets	5
Accounts payable	(16		)
Total purchase price	$	539

Construction Projects in Progress

Development Projects

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Southern Company and Subsidiary Companies 2017 Annual Report

projects, up to 900 MWs in total. Once these wind projects reach commercial operations, which is expected in 2021, they are expected to qualify for 80% PTCs.

The ultimate outcome of these matters cannot be determined at this time.

The following table presents Southern Power's acquisitions for the year ended December 31, 2016.



Project Facility	Resource	Seller, Acquisition Date	Approximate Nameplate Capacity (MW)	Location	Ownership Percentage			Actual COD	PPA Contract Period
Acquisitions for the Year Ended December 31, 2016
Boulder 1	Solar	SunPower November 16, 2016	100	Clark County, NV	51	%	(a)	December 2016	20 years
Calipatria	Solar	Solar Frontier Americas Holding LLC February 11, 2016	20	Imperial County, CA	100	%	(b)	February 2016	20 years
East Pecos	Solar	First Solar, Inc. March 4, 2016	120	Pecos County, TX	100	%		March 2017	15 years
Grant Plains	Wind	Apex Clean Energy Holdings, LLC August 26, 2016	147	Grant County, OK	100	%		December 2016	20 years and 12 years ^(c)
Grant Wind	Wind	Apex Clean Energy Holdings, LLC April 7, 2016	151	Grant County, OK	100	%		April 2016	20 years
Henrietta	Solar	SunPower July 1, 2016	102	Kings County, CA	51	%	(a)	July 2016	20 years
Lamesa	Solar	RES America Developments Inc. July 1, 2016	102	Dawson County, TX	100	%		April 2017	15 years
Mankato ^(d)	Natural Gas	Calpine Corporation October 26, 2016	375	Mankato, MN	100	%		N/A ^(e)	10 years
Passadumkeag	Wind	Quantum Utility Generation, LLC June 30, 2016	42	Penobscot County, ME	100	%		July 2016	15 years
Rutherford	Solar	Cypress Creek Renewables, LLC July 1, 2016	74	Rutherford County, NC	100	%	(b)	December 2016	15 years
Salt Fork	Wind	EDF Renewable Energy, Inc. December 1, 2016	174	Donley and Gray Counties, TX	100	%		December 2016	14 years and 12 years
Tyler Bluff	Wind	EDF Renewable Energy, Inc. December 21, 2016	125	Cooke County, TX	100	%		December 2016	12 years
Wake Wind	Wind	Invenergy October 26, 2016	257	Floyd and Crosby Counties, TX	90.1	%	(f)	October 2016	12 years


(a)	Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction.


(b)	Southern Power originally purchased 90%, with a minority owner owning 10%. During 2017, Southern Power acquired the remaining 10% ownership interest.


(c)	In addition to the 20-year and 12-year PPAs, the facility has a 10-year contract with Allianz Risk Transfer (Bermuda) Ltd.


(d)	Under the terms of the PPA and the expansion PPA, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017.


(e)	The acquisition included a fully operational 375-MW natural gas-fired combined-cycle facility.


(f)	Southern Power owns 90.1%, with the minority owner, Invenergy Wind Global LLC, owning 9.9%.

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Southern Company and Subsidiary Companies 2017 Annual Report

Acquisitions During the Year Ended December 31, 2016



	2016
	(in millions)
CWIP	$	2,354
Property, plant, and equipment	302
Intangible assets ^(a)	128
Other assets	52
Accounts payable	(16		)
Debt	(217		)
Total purchase price	$	2,603

Funded by:
Southern Power ^{(b) (c)}	$	2,345
Noncontrolling interests ^{(d) (e)}	258
Total purchase price	$	2,603


(a)	Intangible assets consist of acquired PPAs that will be amortized over 10- and 20-year terms. The estimated amortization for future periods is approximately $9 million per year. See Note 1 for additional information.


(b)	At December 31, 2016, $461 million is included in acquisitions payable on the balance sheets.


(c)	Includes approximately $281 million of contingent consideration, of which $29 million was payable at December 31, 2017.


(d)	Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders' equity.


(e)	Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests.

Southern Company Gas

Investment in Southern Natural Gas

Acquisition of Remaining Interest in SouthStar

Proposed Sale of Elizabethtown Gas and Elkton Gas

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New Jersey BPU and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018.

The ultimate outcome of these matters cannot be determined at this time.

13. SEGMENT AND RELATED INFORMATION

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 four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four 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 the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations.

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	Electric Utilities
	Traditional Electric Operating Companies			Southern Power			Eliminations			Total		Southern Company Gas		All Other			Eliminations			Consolidated
	(in millions)
2017
Operating revenues	$	16,884		$	2,075		$	(419	)	$	18,540	$	3,920	$	741		$	(170	)	$	23,031
Depreciation and amortization	1,954			503			—			2,457		501		52			—			3,010
Interest income	14			7			—			21		3		11			(9		)	26
Earnings from equity method investments	1			—			—			1		106		(1		)	—			106
Interest expense	820			191			—			1,011		200		490			(7		)	1,694
Income taxes	1,021			(939		)	—			82		367		(307		)	—			142
Segment net income (loss)^(a)(b)(c)	(193		)	1,071			—			878		243		(279		)	—			842
Total assets	72,204			15,206			(325		)	87,085		22,987		2,552			(1,619		)	111,005
Gross property additions	3,836			268			—			4,104		1,525		355			—			5,984
2016
Operating revenues	$	16,803		$	1,577		$	(439	)	$	17,941	$	1,652	$	463		$	(160	)	$	19,896
Depreciation and amortization	1,881			352			—			2,233		238		31			—			2,502
Interest income	6			7			—			13		2		20			(15		)	20
Earnings from equity method investments	2			—			—			2		60		(3		)	—			59
Interest expense	814			117			—			931		81		317			(12		)	1,317
Income taxes	1,286			(195		)	—			1,091		76		(216		)	—			951
Segment net income (loss)^{(a) (b)}	2,233			338			—			2,571		114		(230		)	(7		)	2,448
Total assets	72,141			15,169			(316		)	86,994		21,853		2,474			(1,624		)	109,697
Gross property additions	4,852			2,114			—			6,966		618		41			(1		)	7,624
2015
Operating revenues	$	16,491		$	1,390		$	(439	)	$	17,442	$	—	$	152		$	(105	)	$	17,489
Depreciation and amortization	1,772			248			—			2,020		—		14			—			2,034
Interest income	19			2			1			22		—		6			(5		)	23
Earnings from equity method investments	1			—			—			1		—		(1		)	—			—
Interest expense	697			77			—			774		—		69			(3		)	840
Income taxes	1,305			21			—			1,326		—		(132		)	—			1,194
Segment net income (loss)^{(a) (b)}	2,186			215			—			2,401		—		(32		)	(2		)	2,367
Total assets	69,052			8,905			(397		)	77,560		—		1,819			(1,061		)	78,318
Gross property additions	5,124			1,005			—			6,129		—		40			—			6,169


(a)	Attributable to Southern Company.

(b)


(c)	Segment net income (loss) for the traditional electric operating companies also includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) in 2017. See Note 3 under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.

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Southern Company and Subsidiary Companies 2017 Annual Report

Products and Services



Electric Utilities' Revenues
Year	Retail		Wholesale		Other		Total
	(in millions)
2017	$	15,330	$	2,426	$	784	$	18,540
2016	15,234		1,926		781		17,941
2015	14,987		1,798		657		17,442



Southern Company Gas' Revenues
Year	Gas Distribution Operations		Gas Marketing Services		All Other		Total
	(in millions)
2017	$	3,024	$	860	$	36	$	3,920
2016	1,266		354		32		1,652

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NOTES (continued)

Southern Company and Subsidiary Companies 2017 Annual Report

14. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2017 and 2016 is as follows:



						Consolidated Net Income Attributable to Southern Company			Per Common Share
	Operating Revenues		Operating Income						Basic Earnings			Diluted Earnings					Trading Price Range
Quarter Ended	Operating Revenues		Operating Income						Basic Earnings			Diluted Earnings			Dividends		High		Low
	(in millions)
March 2017	$	5,771	$	1,306		$	658		$	0.66		$	0.66		$	0.5600	$	51.47	$	47.57
June 2017	5,430		(1,594		)	(1,381		)	(1.38		)	(1.37		)	0.5800		51.97		47.87
September 2017	6,201		2,045			1,069			1.07			1.06			0.5800		50.80		46.71
December 2017	5,629		794			496			0.49			0.49			0.5800		53.51		47.92

March 2016	$	3,992	$	940		$	489		$	0.53		$	0.53		$	0.5425	$	51.73	$	46.00
June 2016	4,459		1,185			623			0.67			0.66			0.5600		53.64		47.62
September 2016	6,264		1,917			1,139			1.18			1.17			0.5600		54.64		50.00
December 2016	5,181		587			197			0.20			0.20			0.5600		52.23		46.20

As a result of the Tax Reform Legislation, the Southern Company system recorded a total income tax benefit of $264 million in the fourth quarter 2017. See Note 5 for additional information.

The Southern Company system's business is influenced by seasonal weather conditions.

Table of Contents Index to Financial Statements

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA

For the Periods Ended December 2013 through 2017

Southern Company and Subsidiary Companies 2017 Annual Report



	2017		2016^(a)		2015		2014		2013
Operating Revenues (in millions)	$	23,031	$	19,896	$	17,489	$	18,467	$	17,087
Total Assets (in millions)^(b)(c)	$	111,005	$	109,697	$	78,318	$	70,233	$	64,264
Gross Property Additions (in millions)	$	5,984	$	7,624	$	6,169	$	6,522	$	5,868
Return on Average Common Equity (percent)^(d)	3.44		10.80		11.68		10.08		8.82
Cash Dividends Paid Per Share of Common Stock	$	2.3000	$	2.2225	$	2.1525	$	2.0825	$	2.0125
Consolidated Net Income Attributable to Southern Company (in millions)^(d)	$	842	$	2,448	$	2,367	$	1,963	$	1,644
Earnings Per Share —
Basic	$	0.84	$	2.57	$	2.60	$	2.19	$	1.88
Diluted	0.84		2.55		2.59		2.18		1.87
Capitalization (in millions):
Common stock equity	$	24,167	$	24,758	$	20,592	$	19,949	$	19,008
Preferred and preference stock of subsidiaries and noncontrolling interests	1,361		1,854		1,390		977		756
Redeemable preferred stock of subsidiaries	324		118		118		375		375
Redeemable noncontrolling interests	—		164		43		39		—
Long-term debt^(b)	44,462		42,629		24,688		20,644		21,205
Total (excluding amounts due within one year)	$	70,314	$	69,523	$	46,831	$	41,984	$	41,344
Capitalization Ratios (percent):
Common stock equity	34.4		35.6		44.0		47.5		46.0
Preferred and preference stock of subsidiaries and noncontrolling interests	1.9		2.7		3.0		2.3		1.8
Redeemable preferred stock of subsidiaries	0.5		0.2		0.3		0.9		0.9
Redeemable noncontrolling interests	—		0.2		0.1		0.1		—
Long-term debt^(b)	63.2		61.3		52.6		49.2		51.3
Total (excluding amounts due within one year)	100.0		100.0		100.0		100.0		100.0
Other Common Stock Data:
Book value per share	$	23.99	$	25.00	$	22.59	$	21.98	$	21.43
Market price per share:
High	$	53.51	$	54.64	$	53.16	$	51.28	$	48.74
Low	46.71		46.00		41.40		40.27		40.03
Close (year-end)	48.09		49.19		46.79		49.11		41.11
Market-to-book ratio (year-end) (percent)	200.5		196.8		207.2		223.4		191.8
Price-earnings ratio (year-end) (times)	57.3		19.1		18.0		22.4		21.9
Dividends paid (in millions)	$	2,300	$	2,104	$	1,959	$	1,866	$	1,762
Dividend yield (year-end) (percent)	4.8		4.5		4.6		4.2		4.9
Dividend payout ratio (percent)	273.2		86.0		82.7		95.0		107.1
Shares outstanding (in thousands):
Average	1,000,336		951,332		910,024		897,194		876,755
Year-end	1,007,603		990,394		911,721		907,777		887,086
Stockholders of record (year-end)	120,803		126,338		131,771		137,369		143,800



(a)	The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under "Merger with Southern Company Gas" for additional information.
(b)	A reclassification of debt issuance costs from Total Assets to Long-term debt of $202 million and $139 million is reflected for years 2014 and 2013, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively.
(c)	A reclassification of deferred tax assets from Total Assets of $488 million and $143 million is reflected for years 2014 and 2013, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively.
(d)	A significant loss to income was recorded by Mississippi Power related to the suspension of the Kemper IGCC in June 2017. Earnings in all periods presented were impacted by losses related to the Kemper IGCC.

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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)

For the Periods Ended December 2013 through 2017

Southern Company and Subsidiary Companies 2017 Annual Report



	2017		2016^(a)		2015		2014		2013
Operating Revenues (in millions):
Residential	$	6,515	$	6,614	$	6,383	$	6,499	$	6,011
Commercial	5,439		5,394		5,317		5,469		5,214
Industrial	3,262		3,171		3,172		3,449		3,188
Other	114		55		115		133		128
Total retail	15,330		15,234		14,987		15,550		14,541
Wholesale	2,426		1,926		1,798		2,184		1,855
Total revenues from sales of electricity	17,756		17,160		16,785		17,734		16,396
Natural gas revenues	3,791		1,596		—		—		—
Other revenues	1,484		1,140		704		733		691
Total	$	23,031	$	19,896	$	17,489	$	18,467	$	17,087
Kilowatt-Hour Sales (in millions):
Residential	50,536		53,337		52,121		53,347		50,575
Commercial	52,340		53,733		53,525		53,243		52,551
Industrial	52,785		52,792		53,941		54,140		52,429
Other	846		883		897		909		902
Total retail	156,507		160,745		160,484		161,639		156,457
Wholesale sales	49,034		37,043		30,505		32,786		26,944
Total	205,541		197,788		190,989		194,425		183,401
Average Revenue Per Kilowatt-Hour (cents):
Residential	12.89		12.40		12.25		12.18		11.89
Commercial	10.39		10.04		9.93		10.27		9.92
Industrial	6.18		6.01		5.88		6.37		6.08
Total retail	9.80		9.48		9.34		9.62		9.29
Wholesale	4.95		5.20		5.89		6.66		6.88
Total sales	8.64		8.68		8.79		9.12		8.94
Average Annual Kilowatt-Hour
Use Per Residential Customer	11,618		12,387		13,318		13,765		13,144
Average Annual Revenue
Per Residential Customer	$	1,498	$	1,541	$	1,630	$	1,679	$	1,562
Plant Nameplate Capacity
Ratings (year-end) (megawatts)	46,936		46,291		44,223		46,549		45,502
Maximum Peak-Hour Demand (megawatts):
Winter	31,956		32,272		36,794		37,234		27,555
Summer	34,874		35,781		36,195		35,396		33,557
System Reserve Margin (at peak) (percent)^(b)	30.8		34.2		33.2		19.8		21.5
Annual Load Factor (percent)	61.4		61.5		59.9		59.6		63.2
Plant Availability (percent):
Fossil-steam	84.5		86.4		86.1		85.8		87.7
Nuclear	94.7		93.3		93.5		91.5		91.5



(a)	The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under "Merger with Southern Company Gas" for additional information.
(b)	Beginning in 2014, system reserve margin is calculated to include unrecognized capacity.

Table of Contents Index to Financial Statements

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)

For the Periods Ended December 2013 through 2017

Southern Company and Subsidiary Companies 2017 Annual Report



	2017	2016^(a)	2015	2014	2013
Source of Energy Supply (percent):
Coal	27.0	30.3	32.3	39.3	36.9
Nuclear	14.5	14.5	15.2	14.8	15.5
Oil and gas	41.9	41.7	42.7	37.0	37.2
Hydro	2.1	2.1	2.6	2.5	3.9
Other	5.4	2.4	0.8	0.4	0.1
Purchased power	9.1	9.0	6.4	6.0	6.4
Total	100.0	100.0	100.0	100.0	100.0
Gas Sales Volumes (mmBtu in millions):
Firm	667	296	—	—	—
Interruptible	95	53	—	—	—
Total	762	349	—	—	—
Traditional Electric Operating Company Customers (year-end) (in thousands):
Residential	4,011	3,970	3,928	3,890	3,859
Commercial^(b)	599	595	590	586	582
Industrial^(b)	18	17	17	17	17
Other	12	11	11	11	9
Total electric customers	4,640	4,593	4,546	4,504	4,467
Gas distribution operations customers	4,623	4,586	—	—	—
Total utility customers	9,263	9,179	4,546	4,504	4,467
Employees (year-end)	31,344	32,015	26,703	26,369	26,300



(a)	The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under "Merger with Southern Company Gas" for additional information.
(b)	A reclassification of customers from commercial to industrial is reflected for years 2013-2015 to be consistent with the rate structure approved by the Georgia PSC. The impact to operating revenues, kilowatt-hour sales, and average revenue per kilowatt-hour by class is not material.

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ALABAMA POWER COMPANY

FINANCIAL SECTION

Table of Contents Index to Financial Statements

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Alabama Power Company 2017 Annual Report

/s/ Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President, and Chief Executive Officer

/s/ Philip C. Raymond

Philip C. Raymond

Executive Vice President, Chief Financial Officer, and Treasurer

February 20, 2018

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders and the Board of Directors of Alabama Power Company

Opinion on the Financial Statements

Basis for Opinion

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

/s/ Deloitte & Touche LLP

Birmingham, Alabama

February 20, 2018

We have served as the Company's auditor since 2002.

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DEFINITIONS



Term	Meaning
AFUDC	Allowance for funds used during construction
ARO	Asset retirement obligation
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
CCR	Coal combustion residuals
Clean Air Act	Clean Air Act Amendments of 1990
CO₂	Carbon dioxide
DOE	U.S. Department of Energy
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
IRS	Internal Revenue Service
ITC	Investment tax credit
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
MW	Megawatt
NDR	Natural Disaster Reserve
NO_X	Nitrogen oxide
NRC	U.S. Nuclear Regulatory Commission
OCI	Other comprehensive income
power pool	The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power purchase agreement
PSC	Public Service Commission
Rate CNP	Rate Certificated New Plant
Rate CNP Compliance	Rate Certificated New Plant Compliance
Rate CNP PPA	Rate Certificated New Plant Power Purchase Agreement
Rate ECR	Rate Energy Cost Recovery
Rate NDR	Rate Natural Disaster Reserve
Rate RSE	Rate Stabilization and Equalization plan
ROE	Return on equity
S&P	S&P Global Ratings, a division of S&P Global Inc.
SCS	Southern Company Services, Inc. (the Southern Company system service company)
SEC	U.S. Securities and Exchange Commission
SEGCO	Southern Electric Generating Company
SO₂	Sulfur dioxide
Southern Company	The Southern Company
Southern Company Gas	Southern Company Gas and its subsidiaries

Table of Contents Index to Financial Statements

DEFINITIONS

(continued)



Term	Meaning
Southern Company system	Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SEGCO, Southern Nuclear, SCS, Southern Linc, PowerSecure, Inc. (as of May 9, 2016), and other subsidiaries
Southern Linc	Southern Communications Services, Inc.
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
Tax Reform Legislation	The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018
traditional electric operating companies	Alabama Power Company, Georgia Power, Gulf Power, and Mississippi Power

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Alabama Power Company 2017 Annual Report

OVERVIEW

Business Activities

Many factors affect the opportunities, challenges, and risks of the Company'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, reliability, fuel, capital expenditures, and restoration following major storms. The Company 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 the Company for the foreseeable future.

The Company 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 and preference stock. The Company's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys to evaluate the Company's results and generally targets the top quartile of these surveys in measuring performance.

See RESULTS OF OPERATIONS herein for information on the Company's financial performance.

Earnings

The Company's 2017 net income after dividends on preferred and preference stock was $848 million, representing a $26 million, or 3.2%, increase over the previous year. The increase was primarily due to an increase in rates under Rate RSE effective in January 2017 and the impact of a Rate RSE refund recorded in 2016. These increases to income were partially offset by a decrease in retail revenues associated with milder weather, lower customer usage, and an increase in non-fuel operations and maintenance expenses in 2017 as compared to 2016. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate RSE" herein for additional information.

The Company's 2016 net income after dividends on preferred and preference stock was $822 million, representing a $37 million, or 4.7%, increase over the previous year. The increase was due primarily to an increase in retail revenues under Rate CNP Compliance, an increase in weather-related revenues, and a decrease in operations and maintenance expenses not related to fuel or Rate CNP Compliance. These increases to income were partially offset by an accrual for a Rate RSE refund, a decrease in AFUDC equity, and an increase in depreciation.

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

RESULTS OF OPERATIONS

A condensed income statement for the Company follows:



	Amount			Increase (Decrease) from Prior Year
	2017			2017			2016
	(in millions)
Operating revenues	$	6,039		$	150		$	121
Fuel	1,225			(72		)	(45		)
Purchased power	328			(6		)	(17		)
Other operations and maintenance	1,652			142			9
Depreciation and amortization	736			33			60
Taxes other than income taxes	384			4			12
Total operating expenses	4,325			101			19
Operating income	1,714			49			102
Allowance for equity funds used during construction	39			11			(32		)
Interest expense, net of amounts capitalized	305			3			28
Other income (expense), net	(14		)	7			11
Income taxes	568			37			25
Net income	866			27			28
Dividends on preferred and preference stock	18			1			(9		)
Net income after dividends on preferred and preference stock	$	848		$	26		$	37

Operating Revenues

Operating revenues for 2017 were $6.0 billion, reflecting a $150 million increase from 2016. Details of operating revenues were as follows:



	Amount
	2017			2016
	(in millions)
Retail — prior year	$	5,322		$	5,234
Estimated change resulting from —
Rates and pricing	362			147
Sales decline	(44		)	(20		)
Weather	(89		)	31
Fuel and other cost recovery	(93		)	(70		)
Retail — current year	5,458			5,322
Wholesale revenues —
Non-affiliates	276			283
Affiliates	97			69
Total wholesale revenues	373			352
Other operating revenues	208			215
Total operating revenues	$	6,039		$	5,889
Percent change	2.6		%	2.1		%

Retail revenues in 2017 were $5.5 billion. These revenues increased $136 million, or 2.6%, in 2017 and $88 million, or 1.7%, in 2016, each as compared to the prior year. The increase in 2017 was primarily due to an increase in rates under Rate RSE effective in January 2017, partially offset by a decrease in fuel revenues and milder weather in the first and third quarters 2017

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

as compared to the corresponding periods in 2016. The increase in 2016 was due to an increase in revenues under Rate CNP Compliance as a result of increased net investments, partially offset by a decrease in fuel revenues and an accrual for a Rate RSE refund. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate RSE" for additional information. See "Energy Sales" herein for a discussion of changes in the volume of energy sold, including changes related to sales decline and weather.

Fuel rates billed to customers are designed to fully recover fluctuating fuel and purchased power costs over a period of time. Fuel revenues generally have no effect on net income because they represent the recording of revenues to offset fuel and purchased power expenses. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate ECR" for additional information.

Wholesale revenues from power sales to non-affiliated utilities were as follows:



	2017		2016		2015
	(in millions)
Capacity and other	$	154	$	154	$	140
Energy	122		129		101
Total non-affiliated	$	276	$	283	$	241

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of the Company's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and 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 the Company's variable cost to produce the energy.

In 2017, wholesale revenues from sales to affiliates increased $28 million, or 40.6%, as compared to the prior year. In 2017, KWH sales increased 31.1% as a result of supporting Southern Company system transmission reliability and a 6.9% increase in the price of energy primarily due to higher natural gas prices. In 2016, wholesale revenues from sales to affiliates decreased $15 million, or 17.9%, as compared to the prior year. In 2016, KWH sales decreased 15.7% as a result of lower-cost generation available in the Southern Company system and a 2.6% decrease in the price of energy primarily due to lower natural gas prices.

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2017 and the percent change from the prior year were as follows:



	Total KWHs	Total KWH Percent Change				Weather-Adjusted Percent Change
	2017	2017		2016		2017		2016
	(in billions)
Residential	17.2	(6.1	)%	1.4	%	(1.2	)%	(0.5	)%
Commercial	13.6	(3.4	)	(0.1	)	(1.3	)	(0.5	)
Industrial	22.7	1.7		(4.6	)	1.7		(4.6	)
Other	0.2	(5.0	)	3.8		(5.0	)	3.8
Total retail	53.7	(2.3	)	(1.5	)	(0.1	)%	(2.2	)%
Wholesale
Non-affiliates	5.5	(6.5	)	37.1
Affiliates	4.2	31.1		(15.7	)
Total wholesale	9.7	6.6		12.5
Total energy sales	63.4	(1.0	)%	0.3	%

Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales in 2017 were 2.3% lower than in 2016. Residential sales and commercial sales decreased 6.1% and 3.4% in 2017, respectively, primarily due to milder weather in the first and third quarters 2017 as compared to the corresponding periods in 2016. Weather-adjusted residential sales were 1.2% lower in 2017 primarily due to lower customer usage resulting from an increase in penetration of energy-efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial sales were 1.3% lower in 2017 primarily due to lower customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial sales increased 1.7% in 2017 as compared to 2016 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, and mining sectors offset by the pipelines and paper sectors.

See "Operating Revenues" above for a discussion of significant changes in wholesale revenues from sales to non-affiliates and wholesale revenues from sales to affiliated companies as related to changes in price and KWH sales.

Fuel and Purchased Power Expenses

Fuel costs constitute one of the largest expenses for the Company. The mix of fuel sources for generation of electricity is determined primarily by the unit cost of fuel consumed, demand, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market.

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

Details of the Company's generation and purchased power were as follows:



	2017	2016	2015
Total generation (in billions of KWHs)	60.3	60.2	60.9
Total purchased power (in billions of KWHs)	6.4	7.1	6.3
Sources of generation (percent) —
Coal	50	53	54
Nuclear	24	23	24
Gas	20	19	16
Hydro	6	5	6
Cost of fuel, generated (in cents per net KWH) —
Coal	2.60	2.75	2.83
Nuclear	0.75	0.78	0.81
Gas	2.72	2.67	2.94
Average cost of fuel, generated (in cents per net KWH)^(a)	2.14	2.26	2.34
Average cost of purchased power (in cents per net KWH)^(b)	5.29	4.80	5.66



(a)	KWHs generated by hydro are excluded from the average cost of fuel, generated.
(b)	Average cost of purchased power includes fuel, energy, and transmission purchased by the Company for tolling agreements where power is generated by the provider.

Fuel and purchased power expenses were $1.55 billion in 2017, a decrease of $78 million, or 4.8%, compared to 2016. The decrease was primarily due to a $67 million net decrease related to the volume of KWHs generated and purchased and a $42 million decrease in the average cost of fuel, partially offset by a $31 million increase in the average cost of purchased power.

Fuel and purchased power expenses were $1.63 billion in 2016, a decrease of $62 million, or 3.7%, compared to 2015. The decrease was primarily due to a $61 million decrease in the average cost of purchased power, and a $59 million decrease in the average cost of fuel, partially offset by a $49 million increase related to the volume of KWHs 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 the Company's energy cost recovery clause. The Company, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate ECR" for additional information.

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.

Fuel

Fuel expenses were $1.2 billion in 2017, a decrease of $72 million, or 5.6%, compared to 2016. The decrease was primarily due to a 12.2% increase in the volume of KWHs generated by hydro, a 5.8% decrease in the volume of KWHs generated by coal, and a 5.5% and 3.9% decrease in the average cost of KWHs generated by coal and nuclear fuel, respectively. These decreases were partially offset by an 8.1% increase in the volume of KWHs generated by nuclear fuel and a 4.0% increase in the volume of KWHs generated by natural gas. Fuel expenses were $1.3 billion in 2016, a decrease of $45 million, or 3.4%, compared to 2015. The decrease was primarily due to a 9.2% decrease in the average cost of KWHs generated by natural gas, which excludes tolling agreements, a 4.2% and 3.9% decrease in the volume of KWHs generated by nuclear fuel and coal, respectively, and a 3.7% decrease in the average cost of KWHs generated by nuclear fuel, partially offset by a 17.4% increase in the volume of KWHs generated by natural gas.

Purchased Power – Affiliates

Purchased power expense from affiliates was $158 million in 2017, a decrease of $10 million, or 6.0%, compared to 2016. This decrease was primarily due to a 17.2% decrease in the amount of energy purchased due to milder weather partially offset by a 13.9% increase in the average cost per KWH purchased due to higher natural gas prices. Purchased power expense from affiliates was $168 million in 2016, a decrease of $12 million, or 6.7%, compared to 2015. This decrease was primarily due to a

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Alabama Power Company 2017 Annual Report

20.7% decrease in the average cost per KWH purchased due to lower natural gas prices, partially offset by a 17.5% increase in the amount of energy purchased due to the availability of lower-cost generation compared to the Company's owned generation.

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

In 2016, other operations and maintenance expenses increased $9 million, or 0.6%, as compared to the prior year. Steam production costs increased $28 million primarily due to the timing of generation operating expenses. Transmission and distribution expenses increased $10 million and $7 million, respectively, primarily due to additional vegetation management and other maintenance expenses. These increases were partially offset by a decrease of $32 million in employee benefit costs, including pension costs. The increases in operations and maintenance expenses were primarily Rate CNP compliance-related costs and therefore had no significant impact to net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate CNP Compliance" herein for additional information.

See Note 2 to the financial statements under "Pension Plans" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $33 million, or 4.7%, in 2017 as compared to the prior year primarily due to additional plant in service and an increase in generation-related depreciation rates, effective January 1, 2017, associated with compliance-related steam projects and ARO recovery, partially offset by a decrease in distribution-related depreciation rates. See Note 1 to the financial statements under "Depreciation and Amortization" for additional information. Depreciation and amortization increased $60 million, or 9.3%, in 2016 as compared to the prior year primarily due to compliance-related steam projects placed in service.

Taxes Other Than Income Taxes

Allowance for Equity Funds Used During Construction

AFUDC equity increased $11 million, or 39.3%, in 2017 as compared to the prior year. The increase was primarily associated with steam, transmission, and nuclear construction projects. AFUDC equity decreased $32 million, or 53.3%, in 2016 as compared to the prior year. The decrease was primarily associated with steam generation capital projects being placed in service. See Note 1 to financial statements under "Allowance for Funds Used During Construction" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $3 million, or 1.0%, in 2017 as compared to the prior year. Interest expense, net of amounts capitalized increased $28 million, or 10.2%, in 2016 as compared to the prior year primarily due to an increase in debt outstanding and a reduction in the amounts capitalized. See FUTURE EARNINGS POTENTIAL – "Financing Activities" herein for additional information.

Other Income (Expense), Net

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Alabama Power Company 2017 Annual Report

Income Taxes

Income taxes increased $37 million, or 7.0%, in 2017 as compared to the prior year primarily due to higher pre-tax earnings, an increase in prior year tax return actualization, and an increase in income tax reserves, partially offset by an increase in state income tax credits. The impact to income taxes as a result of Tax Reform Legislation was not material due to the application of regulatory accounting. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 5 to the financial statements for additional information. Income taxes increased $25 million, or 4.9%, in 2016 as compared to the prior year primarily due to higher pre-tax earnings.

Dividends on Preferred and Preference Stock

Dividends on preferred and preference stock increased $1 million, or 5.9%, in 2017 as compared to the prior year. Dividends on preferred and preference stock decreased $9 million, or 34.6%, in 2016 as compared to the prior year. The decrease was primarily due to the redemption in May 2015 of certain series of preferred and preference stock. See Note 6 to the financial statements under "Redeemable Preferred and Preference Stock" for additional information.

Effects of Inflation

The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate RSE" for additional information.

FUTURE EARNINGS POTENTIAL

General

The Company 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 and to wholesale customers in the Southeast. Prices for electric service provided by the Company to retail customers are set by the Alabama PSC under cost-based regulatory principles. Prices for wholesale electric service, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Utility Regulation" herein and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information about regulatory matters.

The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's primary business of providing electric service. These factors include the Company'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 and limited projected demand growth over the next several years. Future earnings will be impacted by customer growth. 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 the Company'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.

On December 22, 2017, Tax Reform Legislation was signed into law and became effective on January 1, 2018, which, among other things, reduces the federal corporate income tax rate to 21% and changes rates of depreciation and the business interest deduction. See "Income Tax Matters – Federal Tax Reform Legislation" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters – Rate RSE" and "Current and Deferred Income Taxes," respectively, for additional information.

Environmental Matters

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Alabama Power Company 2017 Annual Report

flows, and financial condition. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these compliance costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of the environmental laws and regulations discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.

New or revised environmental laws and regulations could affect many areas of the Company'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 fully recovered in rates on a timely basis. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate CNP Compliance" for additional information. 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 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.

Through 2017, the Company has invested approximately $4.7 billion in environmental capital retrofit projects to comply with environmental requirements, with annual totals of approximately $491 million, $260 million, and $349 million for 2017, 2016, and 2015, respectively. Although the timing, requirements, and estimated costs could change as environmental laws and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are initiated or completed, the Company's current compliance strategy estimates capital expenditures of $1.4 billion from 2018 through 2022, with annual totals of approximately $581 million in 2018, $110 million in 2019, $163 million in 2020, $258 million in 2021, and $268 million in 2022. These estimates do not include any potential compliance costs associated with the regulation of CO₂ emissions from fossil fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. The Company also anticipates expenditures associated with ash pond closure and ground water monitoring under the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule), which are reflected in the Company's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.

Environmental Laws and Regulations

Air Quality

The EPA has set National Ambient Air Quality Standards (NAAQS) for six air pollutants (carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and SO₂), which it reviews and revises periodically. Revisions to these standards can require additional emission controls, improvements in control efficiency, or fuel changes which can result in increased compliance and operational costs. NAAQS requirements can also adversely affect the siting of new facilities. In 2015, the EPA published a more stringent eight-hour ozone NAAQS. The EPA plans to complete designations for this rule by no later than April 30, 2018. No areas within the Company's service territory have been or are anticipated to be designated nonattainment under the 2015 ozone NAAQS. In 2010, the EPA revised the NAAQS for SO₂, establishing a new one-hour standard, and is completing designations in multiple phases. The EPA has issued several rounds of area designations and no areas in the vicinity of Company-owned SO₂ sources have been designated nonattainment under the 2010 one-hour SO₂ NAAQS. However, final eight-hour ozone and SO₂ one-hour designations for certain areas are still pending and, if other areas are designated as nonattainment in the future, increased compliance costs could result.

In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) and its NO_X annual, NO_X seasonal, and SO₂ annual programs. CSAPR is an emissions trading program that addresses the impacts of the interstate transport of SO₂ and NO_X emissions from fossil fuel-fired power plants located in upwind states in the eastern half of the U.S. on air quality in downwind states. The Company has fossil fuel-fired generation subject to these requirements. In October 2016, the EPA published a final rule that revised the CSAPR seasonal NO_X program, establishing more stringent NO_X emissions budgets in Alabama. Increases in either future fossil fuel-fired generation or the cost of CSAPR allowances could have a negative financial impact on results of operations for the Company.

The EPA finalized regional haze regulations in 2005 and 2017. These regulations require states, tribal governments, and various federal agencies to develop and implement plans to reduce pollutants that impair visibility and demonstrate reasonable progress toward the goal of restoring natural visibility conditions in certain areas, including national parks and wilderness areas. States must submit a revised state implementation plan (SIP) to the EPA by July 31, 2021, demonstrating reasonable progress towards achieving visibility improvement goals. State implementation of reasonable progress could require further reductions in SO₂ or NO_X emissions, which could result in increased compliance costs.

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Alabama Power Company 2017 Annual Report

In 2015, the EPA published a final rule requiring certain states (including Alabama) to revise or remove the provisions of their SIPs regulating excess emissions at industrial facilities, including electric generating facilities, during periods of startup, shut-down, or malfunction (SSM). The state excess emission rules provide necessary operational flexibility to affected units during periods of SSM and, if removed, could affect unit availability and result in increased operations and maintenance costs for the Company.

Water Quality

In 2015, the EPA finalized the steam electric effluent limitations guidelines (ELG) rule that set national standards for wastewater discharges from steam electric generating units. The rule prohibits effluent discharges of certain wastestreams and imposes stringent arsenic, mercury, selenium, and nitrate/nitrite limits on scrubber wastewater discharges. The revised technology-based limits and compliance dates may require extensive modifications to existing ash and wastewater management systems or the installation and operation of new ash and wastewater management systems. Compliance with the ELG rule is expected to require capital expenditures and increased operational costs primarily affecting the Company's coal-fired electric generation. Compliance applicability dates range from November 1, 2018 to December 31, 2023 with state environmental agencies incorporating specific applicability dates in the NPDES permitting process based on information provided for each waste stream. The EPA has committed to a new rulemaking that could potentially revise the limitations and applicability dates of the ELG rule. The EPA expects to finalize this rulemaking in 2020. The Company continues to monitor the ELG rule and anticipates that approximately 1,000 MWs of the Company's generation will not be available after the compliance date. The ultimate impact of this rule will depend on any new rule-making that revises the limitation and applicable dates. The Company does not anticipate that the unavailability of any units as a result of the ELG rule will have a material impact on the Company's operations or financial condition.

In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all CWA programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, and canals), which could impact new generation projects and permitting and reporting requirements associated with the installation, expansion, and maintenance of transmission and distribution projects. On July 27, 2017, the EPA and the Corps proposed to rescind the 2015 WOTUS rule. The WOTUS rule has been stayed by the U.S. Court of Appeals for the Sixth Circuit since late 2015, but on January 22, 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction over the pending challenges to the rule. On February 6, 2018, the EPA and the Corps published a final rule delaying implementation of the 2015 WOTUS rule to 2020.

Coal Combustion Residuals

Based on cost estimates for closure in place and monitoring of ash ponds pursuant to the CCR Rule, the Company recorded AROs for each CCR unit in 2015. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information regarding the Company's AROs as of December 31, 2017.

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Alabama Power Company 2017 Annual Report

Global Climate Issues

In 2015, the EPA published final rules limiting CO₂ emissions from new, modified, and reconstructed fossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO₂ emission performance standards for existing units (known as the Clean Power Plan or CPP). In February 2016, the U.S. Supreme Court granted a stay of the CPP, which will remain in effect through the resolution of litigation in the U.S. Court of Appeals for the District of Columbia challenging the legality of the CPP and any review by the U.S. Supreme Court. On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including review of the CPP and other CO₂ emissions rules. On October 10, 2017, the EPA published a proposed rule to repeal the CPP and, on December 28, 2017, published an advanced notice of proposed rulemaking regarding a CPP replacement rule.

In 2015, parties to the United Nations Framework Convention on Climate Change, including the United States, adopted the Paris Agreement, which established a non-binding universal framework for addressing greenhouse gas (GHG) emissions based on nationally determined contributions. On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate impact of this agreement or any renegotiated agreement depends on its implementation by participating countries.

The EPA's GHG reporting rule requires annual reporting of GHG emissions expressed in terms of metric tons of CO₂ equivalent emissions for a company's operational control of facilities. Based on ownership or financial control of facilities, the Company's 2016 GHG emissions were approximately 38 million metric tons of CO₂ equivalent. The preliminary estimate of the Company's 2017 GHG emissions on the same basis is approximately 37 million metric tons of CO₂ equivalent.

FERC Matters

The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing and filed their response with the FERC in 2015.

The ultimate outcome of these matters cannot be determined at this time.

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Alabama Power Company 2017 Annual Report

Retail Regulatory Matters

Rate RSE

At December 31, 2016, the Company's retail return exceeded the allowed WCE range which resulted in the Company establishing a $73 million Rate RSE refund liability. In accordance with an Alabama PSC order issued on February 14, 2017, the Company applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below.

Effective in January 2017, Rate RSE increased 4.48%, or $245 million annually. At December 31, 2017, the Company's actual retail return was within the allowed WCE range. On December 1, 2017, the Company made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2018. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remained unchanged for 2018.

In conjunction with Rate RSE, the Company has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time.

Rate CNP PPA

In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company eliminated the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," the Company utilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2017.

Rate CNP Compliance

Rate CNP Compliance allows for the recovery of the Company's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting the Company's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on the Company's revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.

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Alabama Power Company 2017 Annual Report

Rate ECR

On December 5, 2017, the Alabama PSC issued a consent order that the Company leave in effect for 2018 the energy cost recovery rates which began in 2017. Therefore, the Rate ECR factor as of January 1, 2018 remained at 2.015 cents per KWH. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC.

Rate NDR

Environmental Accounting Order

Based on an order from the Alabama PSC, the Company is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. The regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance. See "Environmental Matters – Environmental Laws and Regulations" herein for additional information regarding environmental regulations.

Income Tax Matters

Federal Tax Reform Legislation

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Alabama Power Company 2017 Annual Report

In addition, under the Tax Reform Legislation, net operating losses (NOL) generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income in the subsequent tax year. The projected reduction of Southern Company's consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards.

For the year ended December 31, 2017, implementation of the Tax Reform Legislation resulted in an estimated net tax expense of $3 million, a $271 million decrease in regulatory assets, and a $2.0 billion increase in regulatory liabilities, primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities.

The Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the Alabama PSC. On January 31, 2018, SCS, on behalf of the traditional electric operating companies (including the Company), filed with the FERC a reduction to the Company's open access transmission tariff charge for 2018 to reflect the revised federal corporate tax rate. See Note 3 to the financial statements under "Regulatory Matters – Rate RSE" for additional information.

See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Federal Tax Reform Legislation" for additional information.

The ultimate outcome of these matters cannot be determined at this time.

Bonus Depreciation

Other Matters

The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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Alabama Power Company 2017 Annual Report

Utility Regulation

Federal Tax Reform Legislation

Asset Retirement Obligations

The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.

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Alabama Power Company 2017 Annual Report

Given the significant judgment involved in estimating AROs, the Company considers the liabilities for AROs to be critical accounting estimates.

Pension and Other Postretirement Benefits

See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.

Contingent Obligations

Recently Issued Accounting Standards

Revenue

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

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Alabama Power Company 2017 Annual Report

Leases

In February 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. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.

Other

On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

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Alabama Power Company 2017 Annual Report

Sources of Capital

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Alabama Power Company 2017 Annual Report

At December 31, 2017, the Company had approximately $544 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2017 were as follows:



Expires										Expires Within One Year
2018		2020		2022		Total		Unused		Term Out		No Term Out
(in millions)						(in millions)				(in millions)
$	35	$	500	$	800	$	1,335	$	1,335	$	—	$	35

See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.

Details of short-term borrowings were as follows:



	Short-term Debt at the End of the Period				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)
December 31, 2017	$	3	3.7	%	$	25	1.3	%	$	223
December 31, 2016	$	—	—	%	$	16	0.6	%	$	200
December 31, 2015	$	—	—	%	$	14	0.2	%	$	100


(*)	Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2017, 2016, and 2015.

The Company believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.

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Alabama Power Company 2017 Annual Report

Financing Activities

In February 2017, the Company repaid at maturity $200 million aggregate principal amount of Series 2007A 5.55% Senior Notes.

In October 2017, the Company repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes.

Credit Rating Risk

At December 31, 2017, the Company did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

The maximum potential collateral requirements under these contracts at December 31, 2017 were as follows:



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	1
At BBB- and/or Baa3	$	2
Below BBB- and/or Baa3	$	323

On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the Company) from stable to negative.

On January 19, 2018, Moody's revised its rating outlook for the Company from stable to negative.

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Alabama Power Company 2017 Annual Report

Market Price Risk



	2017 Changes			2016 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	12		$	(54	)
Contracts realized or settled	(1		)	39
Current period changes^(*)	(17		)	27
Contracts outstanding at the end of the period, assets (liabilities), net	$	(6	)	$	12


(*)	Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

The net hedge volumes of energy-related derivative contracts, for the years ended December 31 were as follows:



	2017	2016
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	64	68
Commodity – Natural gas options	5	6
Total hedge volume	69	74

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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

At December 31, 2017 and 2016, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. 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 and were not material for any year presented.



			Fair Value Measurements
			December 31, 2017
	Total		Maturity
	Fair Value		Year 1		Years 2&3
	(in millions)
Level 1	$	—	$	—	$	—
Level 2	6		4		2
Level 3	—		—		—
Fair value of contracts outstanding at end of period	$	6	$	4	$	2

Capital Requirements and Contractual Obligations

The construction program of the Company is currently estimated to total $2.2 billion for 2018, $1.6 billion for 2019, $1.6 billion for 2020, $1.7 billion for 2021, and $1.4 billion for 2022. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $581 million for 2018, $110 million for 2019, $163 million for 2020, $258 million for 2021, and $268 million for 2022. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO₂ emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and "– Global Climate Issues" herein for additional information.

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2017 Annual Report

Contractual Obligations

Contractual obligations at December 31, 2017 were as follows:



	2018		2019- 2020		2021- 2022		After 2022		Total
	(in millions)
Long-term debt^(a) —
Principal	$	—	$	450	$	1,060	$	6,176	$	7,686
Interest	304		598		561		4,408		5,871
Preferred stock dividends^(b)	15		29		29		—		73
Financial derivative obligations^(c)	6		4		—		—		10
Operating leases^(d)	21		40		24		20		105
Capital Lease	1		1		1		2		5
Purchase commitments —
Capital^(e)	2,053		2,972		2,914		—		7,939
Fuel^(f)	974		1,197		459		238		2,868
Purchased power^(g)	78		171		186		606		1,041
Other^(h)	47		73		59		313		492
Pension and other postretirement benefit plans⁽ⁱ⁾	19		36		—		—		55
Total	$	3,518	$	5,571	$	5,293	$	11,763	$	26,145

(a)


(b)	Preferred stock does not mature; therefore, amounts are provided for the next five years only.


(c)	Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, see Notes 1 and 11 to the financial statements.


(d)	Excludes PPAs that are accounted for as leases and are included in purchased power.

(e)

(f)


(g)	Estimated minimum long-term obligations for various long-term commitments for the purchase of capacity and energy.


(h)	Includes long-term service agreements and contracts for the procurement of limestone. Long-term service agreements include price escalation based on inflation indices.