10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2009

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                     to                    

Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address and Telephone Number	Identification No.
1-3526	The Southern Company (A Delaware Corporation)	58-0690070
	30 Ivan Allen Jr. Boulevard, N.W.
	Atlanta, Georgia 30308
	(404) 506-5000
1-3164	Alabama Power Company	63-0004250
	(An Alabama Corporation)
	600 North 18th Street
	Birmingham, Alabama 35291
	(205) 257-1000
1-6468	Georgia Power Company	58-0257110
	(A Georgia Corporation)
	241 Ralph McGill Boulevard, N.E.
	Atlanta, Georgia 30308
	(404) 506-6526
0-2429	Gulf Power Company	59-0276810
	(A Florida Corporation)
	One Energy Place
	Pensacola, Florida 32520
	(850) 444-6111
001-11229	Mississippi Power Company	64-0205820
	(A Mississippi Corporation)
	2992 West Beach
	Gulfport, Mississippi 39501
	(228) 864-1211
333-98553	Southern Power Company	58-2598670
	(A Delaware Corporation)
	30 Ivan Allen Jr. Boulevard, N.W.
	Atlanta, Georgia 30308
	(404) 506-5000

     Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No o

     Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes o No o

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

	Large			Smaller
	Accelerated	Accelerated	Non-accelerated	Reporting
Registrant	Filer	Filer	Filer	Company
The Southern Company	X
Alabama Power Company			X
Georgia Power Company			X
Gulf Power Company			X
Mississippi Power Company			X
Southern Power Company			X

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes o No þ (Response applicable to all registrants.)

	Description of	Shares Outstanding
Registrant	Common Stock	at March 31, 2009
The Southern Company	Par Value $5 Per Share		782,433,682
Alabama Power Company	Par Value $40 Per Share		25,475,000
Georgia Power Company	Without Par Value		9,261,500
Gulf Power Company	Without Par Value		3,142,717
Mississippi Power Company	Without Par Value		1,121,000
Southern Power Company	Par Value $0.01 Per Share		1,000

     This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Southern Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

2

INDEX TO QUARTERLY REPORT ON FORM 10-Q
March 31, 2009

		Page
		Number
DEFINITIONS			5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION			7
	PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	The Southern Company and Subsidiary Companies
	Condensed Consolidated Statements of Income		9
	Condensed Consolidated Statements of Cash Flows		10
	Condensed Consolidated Balance Sheets		11
	Condensed Consolidated Statements of Comprehensive Income		13
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
	Alabama Power Company
	Condensed Statements of Income		30
	Condensed Statements of Comprehensive Income		30
	Condensed Statements of Cash Flows		31
	Condensed Balance Sheets		32
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
	Georgia Power Company
	Condensed Statements of Income		47
	Condensed Statements of Comprehensive Income		47
	Condensed Statements of Cash Flows		48
	Condensed Balance Sheets		49
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		51
	Gulf Power Company
	Condensed Statements of Income		64
	Condensed Statements of Comprehensive Income		64
	Condensed Statements of Cash Flows		65
	Condensed Balance Sheets		66
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		68
	Mississippi Power Company
	Condensed Statements of Income		82
	Condensed Statements of Comprehensive Income		82
	Condensed Statements of Cash Flows		83
	Condensed Balance Sheets		84
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		86
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income		100
	Condensed Consolidated Statements of Comprehensive Income		100
	Condensed Consolidated Statements of Cash Flows		101
	Condensed Consolidated Balance Sheets		102
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		104
	Notes to the Condensed Financial Statements		115
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.		28
Item 4.	Controls and Procedures.		28
Item 4T.	Controls and Procedures.		28

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q
March 31, 2009

		Page
		Number
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	141
Item 1A.	Risk Factors	141
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	Inapplicable
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Submission of Matters to a Vote of Security Holders	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits	142
	Signatures	145

4

DEFINITIONS

Term	Meaning
2007 Retail Rate Plan	Georgia Power’s retail rate plan for the years 2008 through 2010
Alabama Power	Alabama Power Company
Bcf	Billion cubic feet
Clean Air Act	Clean Air Act Amendments of 1990
DOE	U.S. Department of Energy
Duke Energy	Duke Energy Corporation
ECO Plan	Mississippi Power’s Environmental Compliance Overview Plan
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Form 10-K	Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power for the year ended December 31, 2008
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
IGCC	Integrated coal gasification combined cycle
IIC	Intercompany Interchange Contract
IRC	Internal Revenue Code of 1986, as amended
IRS	Internal Revenue Service
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
Mirant	Mirant Corporation
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal unit
MW	Megawatt
MWH	Megawatt-hour
NRC	Nuclear Regulatory Commission
NSR	New Source Review
OCI	Other Comprehensive Income
PEP	Performance Evaluation Plan
Power Pool	The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power Purchase Agreement
PSC	Public Service Commission
Rate ECR	Alabama Power’s energy cost recovery rate mechanism
registrants	Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power
SCS	Southern Company Services, Inc.
SEC	Securities and Exchange Commission
SFAS No. 157	FASB Statement No. 157, “Fair Value Measurement”
Southern Company	The Southern Company
Southern Company system	Southern Company, the traditional operating companies, Southern Power, and other subsidiaries

5

DEFINITIONS
(continued)

Term	Meaning
SouthernLINC Wireless	Southern Communications Services, Inc.
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company
traditional operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
wholesale revenues	revenues generated from sales for resale

6

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the wholesale business, retail sales growth, customer growth, storm damage cost recovery and repairs, fuel cost recovery and other rate actions, environmental regulations and expenditures, earnings growth, dividend payout ratios, access to sources of capital, projections for postretirement benefit and nuclear decommissioning trust contributions, financing activities, completion of construction projects, plans and estimated costs for new generation resources, impacts of adoption of new accounting rules, unrecognized tax benefits related to leveraged lease transactions, impact of the American Recovery and Reinvestment Act of 2009, estimated sales and purchases under new power sale and purchase agreements, and estimated construction and other 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 change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, or particulate matter and other substances, 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;

• current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, IRS audits, and Mirant matters;

• 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, including those relating to weather, the general economy, population and business growth (and declines), and the effects of energy conservation measures;

• available sources and costs of fuels;

• effects of inflation;

• ability to control costs and avoid cost overruns during the development and construction of facilities;

• investment performance of Southern Company’s employee benefit plans;

• 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 storm restoration cost recovery;

• regulatory approvals related to the potential Plant Vogtle expansion, including Georgia PSC and NRC approvals;

• 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, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;

• 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 neighboring utilities and other wholesale customers;

• the direct or indirect effect on Southern Company’s business resulting from terrorist incidents and the threat of terrorist incidents;

• interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company’s and its subsidiaries’ credit ratings;

• the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices;

• catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as an avian or other influenza, or other similar occurrences;

• the direct or indirect effects on Southern Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;

• the effect of accounting pronouncements issued periodically by standard setting bodies; and

• other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the registrants from time to time with the SEC.

Each registrant expressly disclaims any obligation to update any forward-looking statements.

7

THE SOUTHERN COMPANY AND
SUBSIDIARY COMPANIES

8

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009			2008
	(in thousands)
Operating Revenues:
Retail revenues	$	3,064,659		$	3,005,614
Wholesale revenues		451,414			513,662
Other electric revenues		122,798			130,190
Other revenues		27,436			33,444
Total operating revenues		3,666,307			3,682,910
Operating Expenses:
Fuel		1,406,267			1,451,943
Purchased power		107,644			92,904
Other operations and maintenance		871,081			896,817
MC Asset Recovery litigation settlement		202,000			—
Depreciation and amortization		389,758			343,885
Taxes other than income taxes		199,880			189,272
Total operating expenses		3,176,630			2,974,821
Operating Income		489,677			708,089
Other Income and (Expense):
Allowance for equity funds used during construction		42,612			40,585
Interest income		6,908			9,805
Equity in income (losses) of unconsolidated subsidiaries		(976	)		328
Leveraged lease income (losses)		9,441			10,925
Interest expense, net of amounts capitalized		(225,727	)		(217,109	)
Other income (expense), net		(12,850	)		914
Total other income and (expense)		(180,592	)		(154,552	)
Earnings Before Income Taxes		309,085			553,537
Income taxes		167,169			178,138
Consolidated Net Income		141,916			375,399
Dividends on Preferred and Preference Stock of Subsidiaries		16,195			16,195
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	125,721		$	359,204
Common Stock Data:
Earnings per share—
Basic	$	0.16		$	0.47
Diluted	$	0.16		$	0.47
Average number of shares of common stock outstanding (in thousands)
Basic		779,858			766,150
Diluted		781,645			770,322
Cash dividends paid per share of common stock	$	0.4200		$	0.4025

The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

9

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009			2008
	(in thousands)
Operating Activities:
Consolidated net income	$	141,916		$	375,399
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization		456,833			407,689
Deferred income taxes and investment tax credits		(30,386	)		(2,342	)
Deferred revenues		(10,732	)		33,446
Allowance for equity funds used during construction		(42,612	)		(40,585	)
Equity in income (losses) of unconsolidated subsidiaries		976			(328	)
Leveraged lease income (losses)		(9,441	)		(10,925	)
Pension, postretirement, and other employee benefits		7,974			30,916
Stock option expense		16,955			13,427
Derivative fair value adjustments		659			14,380
Hedge settlements		(16,167	)		27,180
MC Asset Recovery litigation settlement		202,000			—
Other, net		6,915			(6,372	)
Changes in certain current assets and liabilities —
Receivables		292,162			188,538
Fossil fuel stock		(160,992	)		(53,305	)
Materials and supplies		(12,648	)		(22,762	)
Other current assets		(67,717	)		(61,320	)
Accounts payable		80,995			(114,636	)
Accrued taxes		(185,215	)		13,865
Accrued compensation		(319,715	)		(265,386	)
Other current liabilities		49,371			10,212
Net cash provided from operating activities		401,131			537,091
Investing Activities:
Property additions		(1,136,212	)		(1,012,907	)
Investment in restricted cash from pollution control revenue bonds		(49,348	)		(145	)
Distribution of restricted cash from pollution control revenue bonds		23,079			35,716
Nuclear decommissioning trust fund purchases		(379,332	)		(160,752	)
Nuclear decommissioning trust fund sales		381,280			153,872
Investment in unconsolidated subsidiaries		(1,800	)		(2,780	)
Cost of removal, net of salvage		(30,231	)		(25,581	)
Other		70,534			17,336
Net cash used for investing activities		(1,122,030	)		(995,241	)
Financing Activities:
Increase (decrease) in notes payable, net		121,274			(100,215	)
Proceeds —
Long-term debt		1,255,925			930,000
Common stock		151,379			132,107
Redemptions —
Long-term debt		(193,417	)		(4,653	)
Preferred and preference stock		—			(125,000	)
Payment of common stock dividends		(326,780	)		(307,960	)
Payment of dividends on preferred and preference stock of subsidiaries		(16,265	)		(17,060	)
Other		(15,618	)		(770	)
Net cash provided from financing activities		976,498			506,449
Net Change in Cash and Cash Equivalents		255,599			48,299
Cash and Cash Equivalents at Beginning of Period		416,581			200,550
Cash and Cash Equivalents at End of Period	$	672,180		$	248,849
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $18,298 and $21,800 capitalized for 2009 and 2008, respectively)	$	178,560		$	197,570
Income taxes (net of refunds)	$	172,517		$	3,719

The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

10

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	At March 31,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	672,180		$	416,581
Restricted cash and cash equivalents		131,609			102,537
Receivables —
Customer accounts receivable		996,427			1,053,674
Unbilled revenues		287,126			320,439
Under recovered regulatory clause revenues		677,665			646,318
Other accounts and notes receivable		353,119			301,028
Accumulated provision for uncollectible accounts		(26,308	)		(26,326	)
Fossil fuel stock, at average cost		1,175,688			1,018,314
Materials and supplies, at average cost		768,777			756,746
Vacation pay		134,581			140,283
Prepaid expenses		337,898			301,570
Other regulatory assets		378,662			275,424
Other		61,324			51,044
Total current assets		5,948,748			5,357,632
Property, Plant, and Equipment:
In service		51,127,521			50,618,219
Less accumulated depreciation		18,517,683			18,285,800
		32,609,838			32,332,419
Nuclear fuel, at amortized cost		547,981			510,274
Construction work in progress		3,609,909			3,035,795
Total property, plant, and equipment		36,767,728			35,878,488
Other Property and Investments:
Nuclear decommissioning trusts, at fair value		809,181			864,396
Leveraged leases		906,805			897,338
Other		223,069			226,757
Total other property and investments		1,939,055			1,988,491
Deferred Charges and Other Assets:
Deferred charges related to income taxes		989,180			972,781
Unamortized debt issuance expense		215,783			207,763
Unamortized loss on reacquired debt		265,711			270,919
Deferred under recovered regulatory clause revenues		366,045			606,483
Other regulatory assets		2,670,820			2,636,217
Other		394,044			428,432
Total deferred charges and other assets		4,901,583			5,122,595
Total Assets	$	49,557,114		$	48,347,206

The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

11

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	At March 31,			At December 31,
Liabilities and Stockholders’ Equity	2009			2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	686,441		$	616,415
Notes payable		1,074,711			953,437
Accounts payable		1,639,403			1,249,694
Customer deposits		312,993			302,495
Accrued taxes —
Income taxes		221,875			195,922
Unrecognized tax benefits		143,858			131,641
Other		183,549			396,206
Accrued interest		225,139			195,500
Accrued vacation pay		169,121			178,519
Accrued compensation		131,092			446,718
Liabilities from risk management activities		354,349			260,977
Other		315,766			298,711
Total current liabilities		5,458,297			5,226,235
Long-term Debt		17,805,963			16,816,438
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		6,064,938			6,080,104
Deferred credits related to income taxes		254,883			259,156
Accumulated deferred investment tax credits		449,263			455,398
Employee benefit obligations		2,056,981			2,057,424
Asset retirement obligations		1,199,752			1,182,769
Other cost of removal obligations		1,333,078			1,320,558
Other regulatory liabilities		251,438			261,970
Other		347,950			329,534
Total deferred credits and other liabilities		11,958,283			11,946,913
Total Liabilities		35,222,543			33,989,586
Redeemable Preferred Stock of Subsidiaries		374,496			374,496
Stockholders’ Equity:
Common Stockholders’ Equity:
Common stock, par value $5 per share —
Authorized — 1 billion shares
Issued — March 31, 2009: 782,865,285 Shares;
— December 31, 2008: 777,615,751 Shares
Treasury — March 31, 2009: 431,603 Shares;
— December 31, 2008: 423,477 Shares
Par value		3,914,294			3,888,041
Paid-in capital		2,036,731			1,892,802
Treasury, at cost		(12,949	)		(12,279	)
Retained earnings		7,411,087			7,611,977
Accumulated other comprehensive loss		(96,455	)		(104,784	)
Total Common Stockholders’ Equity		13,252,708			13,275,757
Preferred and Preference Stock of Subsidiaries		707,367			707,367
Total Stockholders’ Equity		13,960,075			13,983,124
Total Liabilities and Stockholders’ Equity	$	49,557,114		$	48,347,206

The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

12

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009			2008
	(in thousands)
Consolidated Net Income	$	141,916		$	375,399
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $762 and $(13,988), respectively		1,147			(22,251	)
Reclassification adjustment for amounts included in net income, net of tax of $3,833 and $1,778, respectively		6,098			2,775
Marketable securities:
Change in fair value, net of tax of $91 and $(2,137), respectively		734			(3,101	)
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $222 and $259, respectively		350			411
Total other comprehensive income (loss)		8,329			(22,166	)
Dividends on preferred and preference stock of subsidiaries		(16,195	)		(16,195	)
Comprehensive Income	$	134,050		$	337,038

The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

13

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2009 vs. FIRST QUARTER 2008

OVERVIEW

Discussion of the results of operations is focused on Southern Company’s primary business of electricity sales in the Southeast by the traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – and Southern Power. The traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. Southern Company’s other business activities include investments in leveraged lease projects, telecommunications, and energy-related services. For additional information on these businesses, see BUSINESS – The Southern Company System – “Traditional Operating Companies,” “Southern Power,” and “Other Businesses” in Item 1 of the Form 10-K.

Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and earnings per share. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Southern Company in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(233.5)	(65.0)

Southern Company’s first quarter 2009 net income after dividends on preferred and preference stock of subsidiaries was $125.7 million ($0.16 per share) compared to $359.2 million ($0.47 per share) for the first quarter 2008. The decrease for the first quarter 2009 when compared to the same period in 2008 was primarily the result of a litigation settlement agreement with MC Asset Recovery, LLC (MC Asset Recovery); a decrease in contributions from market-response rates to large commercial and industrial customers; and higher depreciation and amortization. The decrease for the first quarter 2009 was partially offset by an increase in customer charges at Alabama Power, increased environmental compliance cost recovery revenues at Georgia Power, and lower other operations and maintenance expenses.

Retail Revenues

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$59.0	2.0

In the first quarter 2009, retail revenues were $3.06 billion compared to $3.01 billion for the same period in 2008. Details of the change to retail revenues follow:

	First Quarter
	2009
	(in millions)			(% change)
Retail – prior year	$	3,005.6
Estimated change in —
Rates and pricing		78.4			2.6
Sales growth (decline)		(56.8	)		(1.9	)
Weather		(4.0	)		(0.1	)
Fuel and other cost recovery		41.5			1.4
Retail – current year	$	3,064.7			2.0	%

14

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Revenues associated with changes in rates and pricing increased in the first quarter 2009 when compared to the same period in 2008 primarily as a result of an increase in customer charges at Alabama Power and increased environmental compliance cost recovery revenues at Georgia Power in accordance with its 2007 Retail Rate Plan, partially offset by a decrease in contributions from market-response rates to large commercial and industrial customers.

Revenues attributable to changes in sales growth declined in the first quarter 2009 when compared to the same period in 2008 due to a 6.3% decrease in weather-adjusted retail KWH sales mainly due to recessionary economic conditions. For the first quarter 2009, weather-adjusted residential KWH sales decreased 0.4%, weather-adjusted commercial KWH sales decreased 1.3%, and weather-adjusted industrial KWH sales decreased 16.9%. Reduced demand in the primary and fabricated metal sectors, as well as in the chemicals, textiles, and transportation sectors, contributed to the decrease in weather-adjusted industrial KWH sales in the first quarter 2009 when compared to the same period in 2008.

Revenues resulting from changes in weather were not material in the first quarter 2009 when compared to the same period in 2008 due to near normal weather in both periods.

Fuel and other cost recovery revenues increased $41.5 million in the first quarter 2009 when compared to the same period in 2008. Electric rates for the traditional 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 fuel component of purchased power costs, and do not affect net income.

Wholesale Revenues

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(62.3)	(12.1)

In the first quarter 2009, wholesale revenues were $451.4 million compared to $513.7 million for the same period in 2008. Wholesale fuel revenues, which are generally offset by wholesale fuel expenses and do not affect net income, decreased $81.7 million in the first quarter 2009 when compared to the same period in 2008. Excluding wholesale fuel revenues, wholesale revenues increased $19.4 million in the first quarter 2009 when compared to the same period in 2008. The increase for the first quarter 2009 was primarily the result of additional revenues associated with Plant Franklin Unit 3 at Southern Power, renegotiated wholesale contracts, and changes in mark-to-market positions on sales of uncontracted generating capacity. Decreases in energy revenues and fewer short-term opportunity sales due to lower energy prices partially offset the first quarter 2009 increase. Short-term opportunity sales are made at market-based rates that generally provide a margin above Southern Company’s variable cost to produce the energy.

Other Electric Revenues

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(7.4)	(5.7)

In the first quarter 2009, other electric revenues were $122.8 million compared to $130.2 million for the same period in 2008. The decrease for the first quarter 2009 when compared to the same period in 2008 was primarily the result of a $9.5 million decrease in co-generation revenues due to lower natural gas prices and a $6.5 million decrease in transmission revenues. The decrease for the first quarter 2009 was partially offset by an increase in revenues from other energy services of $3.3 million, an increase in customer fees of $2.5 million,

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

and an increase in outdoor lighting revenues of $1.3 million. Revenues from co-generation and other energy services are generally offset by related expenses and do not affect net income.

Other Revenues

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(6.0)	(18.0)

In the first quarter 2009, other revenues were $27.4 million compared to $33.4 million for the same period in 2008. The decrease for the first quarter 2009 when compared to the same period in 2008 was primarily the result of a $5.7 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry.

Fuel and Purchased Power Expenses

	First Quarter 2009 vs. First Quarter 2008
	(change in millions)			(% change)
Fuel	$	(45.7	)		(3.1	)
Purchased power		14.7			15.9
Total fuel and purchased power expenses	$	(31.0	)

Fuel and purchased power expenses for the first quarter 2009 were $1.51 billion compared to $1.54 billion for the same period in 2008. The decrease for the first quarter 2009 when compared to the same period in 2008 was primarily the result of a $139.0 million net decrease related to total KWHs generated and purchased, partially offset by a $108.0 million net increase in the average cost of fuel and purchased power, primarily related to a 27.9% increase in the cost of coal per net KWH generated.

Fuel expenses at the traditional operating companies are generally offset by fuel revenues and do not affect net income. See FUTURE EARNINGS POTENTIAL – “FERC and State PSC Matters – Retail 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 affect net income.

Details of Southern Company’s cost of generation and purchased power are as follows:

	First Quarter		First Quarter		Percent
Average Cost	2009		2008		Change
	(cents per net KWH)
Fuel		3.40		3.07		10.8
Purchased power		5.09		6.35		(19.8)

Energy purchases will vary depending on demand for energy within the Southern Company service area, the market cost of available energy as compared to the cost of Southern Company system-generated energy, and the availability of Southern Company system generation.

Other Operations and Maintenance Expenses

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(25.7)	(2.9)

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the first quarter 2009, other operations and maintenance expenses were $871.1 million compared to $896.8 million for the same period in 2008. The decrease for the first quarter 2009 when compared to the same period in 2008 was primarily the result of a $25.3 million decrease in fossil and hydro expenses mainly due to fewer scheduled and unplanned outages; a $13.3 million decrease in transmission and distribution expenses mainly due to lower maintenance expenses; a $7.1 million decrease in expenses primarily related to lower advertising, litigation, and property insurance costs; and a $4.5 million decrease in expenses primarily related to lower sales volume at SouthernLINC Wireless. The decrease for the first quarter 2009 was partially offset by a $27.1 million increase in administration and general expenses largely related to the voluntary attrition program at Georgia Power under which 579 employees elected to resign their positions effective March 31, 2009. The related charge will be largely offset by lower salary costs for the remainder of the year and is not expected to have a material impact on Southern Company’s financial statements for the year ending December 31, 2009.

MC Asset Recovery Litigation Settlement

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$202.0	N/M

N/M — Not Meaningful

In the first quarter 2009, Southern Company entered into a litigation settlement agreement with MC Asset Recovery which resulted in a charge of $202.0 million. See Note (B) to the Condensed Financial Statements under “Mirant Matters — MC Asset Recovery Litigation” herein for additional information.

Depreciation and Amortization

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$45.9	13.3

In the first quarter 2009, depreciation and amortization was $389.8 million compared to $343.9 million for the same period in 2008. The increase for the first quarter 2009 when compared to the same period in 2008 was primarily the result of an increase in plant in service related to environmental and transmission projects at Alabama Power and environmental, transmission, and distribution projects at Georgia Power. An increase in depreciation rates at Southern Power also contributed to the first quarter 2009 increase, as well as the completion of Southern Power’s Plant Franklin Unit 3 in June 2008.

Taxes Other Than Income Taxes

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$10.6	5.6

In the first quarter 2009, taxes other than income taxes were $199.9 million compared to $189.3 million for the same period in 2008. The increase for the first quarter 2009 when compared to the same period in 2008 was primarily the result of increases in franchise fees and municipal gross receipt taxes associated with increases in revenues from retail energy sales. Higher ad valorem taxes at Georgia Power also contributed to the first quarter 2009 increase.

Other Income (Expense), Net

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(13.8)	N/M

N/M — Not Meaningful

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the first quarter 2009, other income (expense), net was $(12.9) million compared to $0.9 million for the same period in 2008. The decrease for the first quarter 2009 when compared to the same period in 2008 was primarily the result of the 2008 recognition of a $6.4 million fee received for participating in an asset auction and a $6.0 million gain on the sale of an undeveloped tract of land to the Orlando Utilities Commission.

Income Taxes

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(10.9)	(6.2)

In the first quarter 2009, income taxes were $167.2 million compared to $178.1 million for the same period in 2008. The decrease for the first quarter 2009 when compared to the same period in 2008 was primarily the result of lower pre-tax earnings, partially offset by a decrease in the IRC Section 199 production activities deduction. See Note (H) to the Condensed Financial Statements under “Effective Tax Rate” herein for details regarding the impact of the MC Asset Recovery litigation settlement on the effective tax rate.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above 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 Southern Company’s primary business of selling electricity. These factors include the traditional operating companies’ ability to maintain a constructive regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Other major factors include profitability of the competitive wholesale supply business and federal regulatory policy, which may impact Southern Company’s level of participation in this market. Future earnings for the electricity business in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities and other wholesale customers, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service area. In addition, the level of future earnings for the wholesale supply business also depends on numerous factors including creditworthiness of customers, total generating capacity available in the Southeast, and the successful remarketing of capacity as current contracts expire. Recent recessionary conditions have negatively impacted sales growth for the traditional operating companies and have negatively impacted wholesale capacity revenues at Southern Power. The current economic recession is expected to continue to have a negative impact on energy sales, particularly to industrial customers. The timing and extent of the economic recovery will impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters” in Item 8 of the Form 10-K for additional information.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Southern Company in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 17, 2009, the EPA released a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. The ultimate outcome of the proposed endangerment finding cannot be determined at this time and will depend on additional regulatory action and potential legal challenges. However, regulatory decisions that may follow from such a finding could have implications for both new and existing stationary sources, such as power plants. In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Southern Company’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

FERC and State PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. Implementation of the energy auction in accordance with the MBR tariff order is expected to adequately mitigate going forward any presumption of market power that Southern Company may have in the Southern

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Company retail service territory. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Fuel Cost Recovery

The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Over the past several years, the traditional operating companies have experienced higher than expected fuel costs for coal, natural gas, and uranium. These higher fuel costs have resulted in under recovered fuel costs included in the balance sheets of approximately $1.0 billion at March 31, 2009 as compared to $1.2 billion at December 31, 2008. Operating revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes to the billing factors will have no significant effect on Southern Company’s revenues or net income but will affect cash flow. The traditional operating companies continuously monitor the under recovered fuel cost balance in light of these higher fuel costs. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Alabama Power Retail Regulatory Matters,” “Georgia Power Retail Regulatory Matters,” and “Gulf Power Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information.

On March 10, 2009, the Georgia PSC granted Georgia Power’s request to delay its fuel case filing until September 4, 2009. The extension was requested as a result of difficulty in establishing a forward-looking fuel rate due to volatile coal and gas prices, uncertain sales forecasts, and a continuing decline in the State of Georgia’s economy. New fuel rates are expected to become effective January 1, 2010. The ultimate outcome of this matter cannot now be determined.

Income Tax Matters

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Southern Company. Southern Company estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $225 million and $275 million. Southern Company is currently assessing the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Construction Projects

Integrated Coal Gasification Combined Cycle

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Construction Projects – Integrated Coal Gasification Combined Cycle” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K for information regarding the Kemper IGCC.

On April 6, 2009, the Governor of the State of Mississippi signed into law a bill that will provide an ad valorem tax exemption for a portion of the assessed value of all property utilized in certain electric generating facilities with integrated gasification process facilities. This tax exemption, which may not exceed 50% of the total value of the project, is for projects with a capital investment from private sources of $1 billion or more.

On April 6, 2009, Mississippi Power received an accounting order from the Mississippi PSC directing Mississippi Power to continue to charge all Kemper IGCC generation resources planning, evaluation, and

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

screening costs to regulatory assets including those costs associated with activities to obtain a certificate of public convenience and necessity and costs necessary and prudent to preserve the availability, economic viability, and/or required schedule of the selected generation resource until the Mississippi PSC makes findings and determination as to the recovery of Mississippi Power’s prudent expenditures.

As of March 31, 2009, Mississippi Power had spent a total of $50.7 million associated with Mississippi Power’s generation resource planning, evaluation, and screening activities, including regulatory filings costs. Costs incurred during the first quarter 2009 totaled $8.4 million as compared to $7.2 million during the first quarter 2008. Of the total $50.7 million, $46.2 million was deferred in other regulatory assets, $3.7 million was related to land purchases capitalized, and $0.8 million was previously expensed.

Several motions have been filed by intervenors in this proceeding, most of which are procedural in nature and seek to stay or delay the timely and orderly administration of the docket. In addition to these procedural motions, a motion has been filed by the Attorney General for the State of Mississippi which questions whether the Mississippi PSC has authority to approve the gasification portion of the Kemper IGCC. All of these motions were heard by the Mississippi PSC on May 5, 2009.

The ultimate outcome of these matters cannot now be determined.

Nuclear

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Construction Projects – Nuclear” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Nuclear” in Item 8 of the Form 10-K for information regarding the potential expansion of Plant Vogtle.

On March 17, 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 at an in-service cost of $6.4 billion. In addition, the Georgia PSC voted to approve inclusion of the related construction work in progress accounts in rate base and to recover financing costs during the construction period beginning in 2011.

On April 21, 2009, the Governor of the State of Georgia signed into law The Georgia Nuclear Energy Financing Act that will allow Georgia Power to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period. The cost recovery provisions will become effective January 1, 2011.

Other Matters

Southern Company is involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, Southern Company is subject to certain claims and legal actions arising in the ordinary course of business. Southern Company’s business activities are subject to extensive governmental regulation related to public health and the environment. 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 opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. 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 or in Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Company’s financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

See the Notes to the Condensed Financial Statements herein for 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

Southern Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, and Unbilled Revenues.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Company’s financial condition remained stable at March 31, 2009. Throughout the recent turmoil in the financial markets, Southern Company has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper programs and variable rate pollution control revenue bonds. Southern Company and the other registrants have continued to issue commercial paper at reasonable rates. Southern 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. Market rates for committed credit have increased, and Southern Company and its subsidiaries have been and expect to continue to be subject to higher costs as existing facilities are replaced or renewed. Of the $215 million of facilities expiring in the first quarter 2009, $160 million of them were replaced or renewed. In addition, Gulf Power entered into a $20 million facility and Mississippi Power increased an existing facility by $10 million. Subsequent to March 31, 2009, Georgia Power, Gulf Power, and Mississippi Power entered into new credit arrangements resulting in a net increase of $425 million, $75 million, and $40 million, respectively. These additional facilities all expire in 2010. Total committed credit fees at Southern Company and its subsidiaries average less than ¹/4 of 1% per year. Southern Company’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of the financial turmoil cannot be determined at this time. Southern Company experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

Southern Company’s investments in pension and nuclear decommissioning trust funds have continued to decline in value during the first quarter 2009. Southern Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2011 and such contribution could be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time. Southern Company does not expect any changes to funding obligations to the nuclear decommissioning trusts prior to 2011.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Net cash provided from operating activities totaled $401 million for the first quarter 2009, a decrease of $136 million from the same period in 2008. Significant changes in operating cash flow for the first quarter 2009 as compared to the prior period include increases in the use of funds for federal tax and property tax payments of $199 million and fuel purchases of $108 million. These uses of funds were partially offset by increased cash inflows as a result of higher fuel rates included in customer billings. Net cash used for investing activities totaled $1.12 billion for the first quarter 2009, an increase of $127 million over the prior period, primarily due to property additions to utility plant. For the first quarter 2009, net cash provided from financing activities totaled $976 million compared to $506 million for the first quarter 2008. The $470 million increase is primarily due to higher levels of short-term borrowings and the issuance of new long-term debt.

Significant balance sheet changes for the first quarter 2009 include an increase of $256 million in cash and cash equivalents primarily due to an increase in temporary cash investments and an increase of $889 million in total property, plant, and equipment for the installation of equipment to comply with environmental standards, construction of generation, transmission and distribution facilities, and purchases of nuclear fuel. Other significant changes include an increase in long-term debt, excluding amounts due within one year, of $990 million used primarily for construction expenditures and general corporate purposes.

The market price of Southern Company’s common stock at March 31, 2009 was $30.62 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $16.94 per share, representing a market-to-book ratio of 181%, compared to $37.00, $17.08, and 217%, respectively, at the end of 2008. The dividend for the first quarter 2009 was $0.42 per share compared to $0.4025 per share in the first quarter 2008. In April 2009, the quarterly dividend payable in June 2009 was increased to $0.4375 per share.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Southern Company in Item 7 of the Form 10-K for a description of Southern Company’s capital requirements for its construction program and other funding requirements associated with scheduled maturities of long-term debt, as well as the related interest, preferred and preference stock dividends, leases, trust funding requirements, other purchase commitments, unrecognized tax benefits and interest, and derivative obligations. Approximately $686 million will be required through March 31, 2010 for maturities of long-term debt. 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 statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. Equity capital can be provided from any combination of Southern Company’s stock plans, private placements, or public offerings. The amount and timing of additional equity capital to be raised in 2009, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities. The traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, security issuances, term loans, short-term borrowings, and equity contributions from Southern Company.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

However, the amount, type, and timing of any financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Southern Company in Item 7 of the Form 10-K for additional information.

Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs (which are backed by bank credit facilities) to meet liquidity needs. At March 31, 2009, Southern Company and its subsidiaries had approximately $672 million of cash and cash equivalents and approximately $4.2 billion of unused credit arrangements with banks, of which $775 million expire in 2009, $160 million expire in 2010, $25 million expire in 2011, and $3.2 billion expire in 2012. Approximately $94 million of the credit facilities expiring in 2009 and 2010 allow for the execution of term loans for an additional two-year period, and $504 million contain provisions allowing one-year term loans. At March 31, 2009, approximately $1.3 billion of the credit facilities were dedicated to providing liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds. See Note 6 to the financial statements of Southern Company under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. The traditional operating companies 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 each of the traditional operating companies. At March 31, 2009, the Southern Company system had outstanding commercial paper of $915.6 million and short-term bank notes of $150 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Off-Balance Sheet Financing Arrangements

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Off-Balance Sheet Financing Arrangements” of Southern Company in Item 7 and Note 7 to the financial statements of Southern Company under “Operating Leases” in Item 8 of the Form 10-K for information related to Mississippi Power’s lease of a combined cycle generating facility at Plant Daniel.

Credit Rating Risk

Southern 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 contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation. At March 31, 2009, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $403 million. At March 31, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.9 billion. In addition, certain nuclear fuel agreements could require collateral of up to $251 million in the event of a rating change to below investment grade for Southern Company. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Company’s ability to access capital markets, particularly the short-term debt market.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Market Price Risk

Southern Company’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Southern Company is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation, the traditional operating companies continue to have limited exposure to market volatility in interest 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, during 2009, Southern Power is exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs. To mitigate residual risks relative to movements in electricity prices, the traditional operating companies enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the registrants may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. As such, the traditional operating companies have no material change in market risk exposure when compared with the December 31, 2008 reporting period.

The changes in fair value of energy-related derivative contracts for the three months ended March 31, 2009 were as follows:

	First Quarter
	2009
	Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(285	)
Contracts realized or settled		60
Current period changes(a)		(198	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(423	)

(a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

The decrease in the fair value positions of the energy-related derivative contracts for the three months ended March 31, 2009 was $138 million, substantially all of which is due to natural gas positions. This change is attributable to both the volume and prices of natural gas. At March 31, 2009, Southern Company had a net hedge volume of 172.6 Bcf (includes location basis of 2 Bcf) with a weighted average contract cost approximately $2.53 per mmBtu above market prices, compared to 148.8 Bcf at December 31, 2008 with a weighted average contract cost approximately $1.97 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the traditional operating companies’ fuel cost recovery clauses.

25

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At March 31, 2009, the fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:

	March 31, 2009
	(in millions)
Regulatory hedges	$	(427	)
Cash flow hedges		1
Not designated		3
Total fair value	$	(423	)

Energy-related derivative contracts which are designated as regulatory hedges relate to the traditional operating companies’ fuel hedging programs, where 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 fuel cost recovery clauses. Gains and losses on energy-related derivatives designated as cash flow hedges are mainly used by Southern Power to hedge anticipated purchases and sales and are initially deferred in other comprehensive income 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.

Total net unrealized pre-tax losses recognized in the statements of income for the three months ended March 31, 2009 for energy-related derivative contracts that are not hedges were $1 million. For the three months ended March 31, 2008, the total net unrealized losses recognized in the statements of income were $14 million. See Note (F) to the Condensed Financial Statements herein for further details of these losses.

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2009 are as follows:

	March 31, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(423	)		(319	)		(99	)		(5	)
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(423	)	$	(319	)	$	(99	)	$	(5	)

Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Southern Company in Item 7 and Notes 1 and 6 to the financial statements of Southern Company under “Financial Instruments” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein.

26

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

In the first three months of 2009, Southern Company’s subsidiaries issued $1.1 billion of senior notes, and Southern Company issued $151 million of common stock through the Southern Investment Plan and employee and director stock plans. The proceeds were primarily used to fund ongoing construction projects and to repay short-term and long-term indebtedness. Alabama Power issued $500 million of Series 2009A 6.00% Senior Notes due March 1, 2039. Alabama Power used the proceeds to repay short-term indebtedness and for other general corporate purposes, including Alabama Power’s continuous construction program. Georgia Power issued $500 million of Series 2009A 5.95% Senior Notes due February 1, 2039. Georgia Power used the proceeds to repay $150 million aggregate principal amount of its Series U Floating Rate Senior Notes at maturity, to repay a portion of short-term indebtedness, and for general corporate purposes, including Georgia Power’s continuous construction program. Georgia Power settled $100 million of hedges related to the Series 2009A issuance at a loss of approximately $16 million, and this loss will be amortized to interest expense, in earnings, together with a previously settled loss of approximately $2 million, over 10 years. Mississippi Power issued $125 million of Series 2009A 5.55% Senior Notes due March 1, 2019. Mississippi Power used the proceeds to repay at maturity Mississippi Power’s $40 million aggregate principal amount of Series F Floating Rate Senior Notes due March 9, 2009, to repay a portion of short-term indebtedness, and for general corporate purposes, including Mississippi Power’s continuous construction program. Gulf Power also incurred obligations related to the issuance of pollution control revenue bonds totaling approximately $130 million. Gulf Power is using the proceeds for acquisition, construction, installation, and equipping of certain solid waste disposal facilities located at Plant Crist. See Southern Company’s Condensed Consolidated Statements of Cash Flows herein for further details regarding financing activities during the first three months of 2009.

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.

27

PART I

Item 3. Quantitative And Qualitative Disclosures About Market Risk.

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” herein for each registrant and Notes 1 and 6 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power under “Financial Instruments” in Item 8 of the Form 10-K. Also, see Note (F) to the Condensed Financial Statements herein for information relating to derivative instruments.

Item 4. Controls and Procedures.

     (a) Evaluation of disclosure controls and procedures.

As of the end of the period covered by this quarterly report, Southern Company conducted an evaluation under the supervision and with the participation of Southern Company’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based upon this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective.

     (b) Changes in internal controls.

There have been no changes in Southern Company’s 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) during the first quarter 2009 that have materially affected or are reasonably likely to materially affect Southern Company’s internal control over financial reporting.

Item 4T. Controls and Procedures.

     (a) Evaluation of disclosure controls and procedures.

As of the end of the period covered by this quarterly report, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power conducted separate evaluations under the supervision and with the participation of each company’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.

     (b) Changes in internal controls.

There have been no changes in Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s 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) during the first quarter 2009 that have materially affected or are reasonably likely to materially affect Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting.

28

ALABAMA POWER COMPANY

29

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009			2008
	(in thousands)
Operating Revenues:
Retail revenues	$	1,058,137		$	1,034,254
Wholesale revenues —
Non-affiliates		158,695			170,040
Affiliates		84,352			83,692
Other revenues		38,582			48,693
Total operating revenues		1,339,766			1,336,679
Operating Expenses:
Fuel		483,233			453,149
Purchased power —
Non-affiliates		15,544			11,219
Affiliates		41,560			88,707
Other operations and maintenance		276,859			309,550
Depreciation and amortization		143,416			124,637
Taxes other than income taxes		80,281			75,771
Total operating expenses		1,040,893			1,063,033
Operating Income		298,873			273,646
Other Income and (Expense):
Allowance for equity funds used during construction		16,725			11,304
Interest income		4,122			4,642
Interest expense, net of amounts capitalized		(72,207	)		(68,976	)
Other income (expense), net		(6,372	)		(7,222	)
Total other income and (expense)		(57,732	)		(60,252	)
Earnings Before Income Taxes		241,141			213,394
Income taxes		85,009			73,428
Net Income		156,132			139,966
Dividends on Preferred and Preference Stock		9,866			9,866
Net Income After Dividends on Preferred and Preference Stock	$	146,266		$	130,100

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009			2008
	(in thousands)
Net Income After Dividends on Preferred and Preference Stock	$	146,266		$	130,100
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(886) and $(2,211), respectively		(1,457	)		(3,637	)
Reclassification adjustment for amounts included in net income, net of tax of $1,061 and $185, respectively		1,745			305
Total other comprehensive income (loss)		288			(3,332	)
COMPREHENSIVE INCOME	$	146,554		$	126,768

The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

30

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	156,132		$	139,966
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization		164,488			146,208
Deferred income taxes and investment tax credits, net		(25,795	)		4,513
Allowance for equity funds used during construction		(16,725	)		(11,304	)
Pension, postretirement, and other employee benefits		(4,933	)		(3,995	)
Stock option expense		2,851			2,178
Tax benefit of stock options		24			347
Other, net		8,834			9,223
Changes in certain current assets and liabilities —
Receivables		173,032			62,227
Fossil fuel stock		(11,654	)		(34,750	)
Materials and supplies		(6,775	)		(7,751	)
Other current assets		(73,518	)		(63,757	)
Accounts payable		(136,678	)		(124,727	)
Accrued taxes		123,746			79,338
Accrued compensation		(64,030	)		(64,851	)
Other current liabilities		7,928			9,357
Net cash provided from operating activities		296,927			142,222
Investing Activities:
Property additions		(337,984	)		(349,683	)
Investment in restricted cash from pollution control revenue bonds		(160	)		(145	)
Distribution of restricted cash from pollution control revenue bonds		13,774			19,622
Nuclear decommissioning trust fund purchases		(60,600	)		(46,941	)
Nuclear decommissioning trust fund sales		60,600			46,941
Cost of removal, net of salvage		(5,109	)		(8,863	)
Other		3,025			13,453
Net cash used for investing activities		(326,454	)		(325,616	)
Financing Activities:
Decrease in notes payable, net		(24,995	)		—
Proceeds —
Common stock issued to parent		—			150,000
Capital contributions		6,682			6,016
Gross excess tax benefit of stock options		47			607
Senior notes		500,000			300,000
Redemptions —
Preferred stock		—			(125,000	)
Payment of preferred and preference stock dividends		(9,868	)		(11,275	)
Payment of common stock dividends		(130,700	)		(122,825	)
Other		(5,869	)		(1,684	)
Net cash provided from financing activities		335,297			195,839
Net Change in Cash and Cash Equivalents		305,770			12,445
Cash and Cash Equivalents at Beginning of Period		28,181			73,616
Cash and Cash Equivalents at End of Period	$	333,951		$	86,061
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $6,992 and $5,130 capitalized for 2009 and 2008, respectively)	$	54,875		$	63,324
Income taxes (net of refunds)	$	(640	)	$	1,550

The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

31

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At March 31,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	333,951		$	28,181
Restricted cash and cash equivalents		66,466			80,079
Receivables —
Customer accounts receivable		343,870			350,410
Unbilled revenues		89,450			98,921
Under recovered regulatory clause revenues		204,804			153,899
Other accounts and notes receivable		29,649			44,645
Affiliated companies		60,765			70,612
Accumulated provision for uncollectible accounts		(9,161	)		(8,882	)
Fossil fuel stock, at average cost		330,134			322,089
Materials and supplies, at average cost		312,416			305,880
Vacation pay		52,701			52,577
Prepaid expenses		130,271			88,219
Other regulatory assets		105,654			74,825
Other		12,772			12,915
Total current assets		2,063,742			1,674,370
Property, Plant, and Equipment:
In service		17,789,435			17,635,129
Less accumulated provision for depreciation		6,346,622			6,259,720
		11,442,813			11,375,409
Nuclear fuel, at amortized cost		255,818			231,862
Construction work in progress		1,243,412			1,092,516
Total property, plant, and equipment		12,942,043			12,699,787
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		51,745			50,912
Nuclear decommissioning trusts, at fair value		376,606			403,966
Other		63,496			62,782
Total other property and investments		491,847			517,660
Deferred Charges and Other Assets:
Deferred charges related to income taxes		369,991			362,596
Prepaid pension costs		176,613			166,334
Deferred under recovered regulatory clause revenues		—			180,874
Other regulatory assets		761,831			732,367
Other		206,178			202,018
Total deferred charges and other assets		1,514,613			1,644,189
Total Assets	$	17,012,245		$	16,536,006

The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

32

ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)

	At March 31,			At December 31,
Liabilities and Stockholder’s Equity	2009			2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	250,040		$	250,079
Notes payable		—			24,995
Accounts payable —
Affiliated		140,190			178,708
Other		272,427			358,176
Customer deposits		81,730			77,205
Accrued taxes —
Income taxes		143,306			18,299
Other		49,447			30,372
Accrued interest		67,393			56,375
Accrued vacation pay		44,217			44,217
Accrued compensation		26,973			91,856
Liabilities from risk management activities		116,330			83,873
Other		43,075			53,777
Total current liabilities		1,235,128			1,267,932
Long-term Debt		6,103,870			5,604,791
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		2,192,025			2,243,117
Deferred credits related to income taxes		90,806			90,083
Accumulated deferred investment tax credits		170,653			172,638
Employee benefit obligations		399,844			396,923
Asset retirement obligations		468,632			461,284
Other cost of removal obligations		655,389			634,792
Other regulatory liabilities		79,371			79,151
Other		51,638			45,858
Total deferred credits and other liabilities		4,108,358			4,123,846
Total Liabilities		11,447,356			10,996,569
Preferred and Preference Stock		685,127			685,127
Common Stockholder’s Equity:
Common stock, par value $40 per share —
Authorized - 40,000,000 shares
Outstanding - 25,475,000 shares		1,019,000			1,019,000
Paid-in capital		2,101,062			2,091,462
Retained earnings		1,769,361			1,753,797
Accumulated other comprehensive loss		(9,661	)		(9,949	)
Total common stockholder’s equity		4,879,762			4,854,310
Total Liabilities and Stockholder’s Equity	$	17,012,245		$	16,536,006

The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

33

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2009 vs. FIRST QUARTER 2008

OVERVIEW

Alabama Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Alabama Power’s primary business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain energy sales in the midst of the current economic downturn, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel prices, capital expenditures, and restoration following major storms. Appropriately balancing the need to recover these increasing costs with customer prices will continue to challenge Alabama Power for the foreseeable future.

Alabama Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Alabama Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$16.2	12.4

Alabama Power’s financial performance remained stable in the first quarter 2009 despite the continued challenges of a recessionary economy. Alabama Power’s net income after dividends on preferred and preference stock for the first quarter 2009 was $146.3 million compared to $130.1 million for the same period in 2008. The increase was primarily due to the corrective rate package providing for adjustments associated with customer charges to certain existing rate structures effective in January 2009, and a decrease in other operations and maintenance expenses related to steam power associated with fewer scheduled outages. The increase was partially offset by a decline in sales growth and increases in income taxes and depreciation and amortization resulting from additional plant in service.

Retail Revenues

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$23.9	2.3

In the first quarter 2009, retail revenues were $1.06 billion compared to $1.03 billion for the same period in 2008.

34

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the change to retail revenues are as follows:

	First Quarter
	2009
	(in millions)			(% change)
Retail – prior year	$	1,034.3
Estimated change in —
Rates and pricing		49.6			4.8
Sales growth (decline)		(32.4	)		(3.1	)
Weather		(0.7	)		(0.1	)
Fuel and other cost recovery		7.3			0.7
Retail – current year	$	1,058.1			2.3	%

Revenues associated with changes in rates and pricing increased in the first quarter 2009 when compared to the same period in 2008 primarily due to the corrective rate package increase effective January 2009, which mainly provided for adjustments associated with customer charges to certain existing rate structures. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Rate Adjustments” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales growth declined due to a recessionary economy in the first quarter 2009 when compared to the same period in 2008. Weather-adjusted residential KWH energy sales decreased 2.6% driven by a decline in customer demand related to customer energy efficiency efforts in addition to a recessionary economy. Industrial KWH energy sales decreased 21.6% due to a broad decline in demand across all industrial segments. Weather-adjusted commercial KWH energy sales decreased 2.5% due to a decline in customer demand.

Revenues resulting from changes in weather were relatively flat in the first quarter 2009 when compared to the same period in 2008.

Fuel and other cost recovery revenues increased in the first quarter 2009 when compared to the same period in 2008 due to increases in fuel costs. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not impact net income.

Wholesale Revenues – Non-Affiliates

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(11.3)	(6.7)

Wholesale revenues from non-affiliates will vary depending on the market cost of available energy compared to the cost of Alabama Power and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation. In the first quarter 2009, wholesale revenues from non-affiliates were $158.7 million compared to $170.0 million for the same period in 2008. This decrease was primarily due to a 7.8% reduction in price.

35

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Revenues

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(10.1)	(20.8)

In the first quarter 2009, other revenues were $38.6 million compared to $48.7 million for the same period in 2008. This decrease was primarily due to a decrease of $9.5 million in revenues from gas-fueled co-generation steam facilities resulting from lower gas prices.

Co-generation steam fuel revenues do not have a significant impact on earnings since they are generally offset by fuel expense.

Fuel and Purchased Power Expenses

	First Quarter 2009 vs. First Quarter 2008
	(change in millions)			(% change)
Fuel	$	30.1			6.6
Purchased power – non-affiliates		4.3			38.6
Purchased power – affiliates		(47.1	)		(53.1	)
Total fuel and purchased power expenses	$	(12.7	)

In the first quarter 2009, total fuel and purchased power expenses were $540.4 million compared to $553.1 million for the same period in 2008. This decrease was primarily due to a $68.8 million decrease in total KWHs generated and purchased, partially offset by a $56.1 million increase in the cost of energy resulting from an increase in the average cost of coal.

Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Rate ECR. See FUTURE EARNINGS POTENTIAL – “FERC and Alabama PSC Matters – Retail Fuel Cost Recovery” herein for additional information.

Details of Alabama Power’s cost of generation and purchased power are as follows:

	First Quarter		First Quarter		Percent
Average Cost	2009		2008		Change
	(cents per net KWH)
Fuel		2.92		2.60		12.3
Purchased power		6.14		5.67		8.3

In the first quarter 2009, fuel expense was $483.3 million compared to $453.2 million for the same period in 2008. The increase was due to a 12.3% increase in the average cost of fuel per KWH generated, primarily due to the price of fuels. The average cost of coal per KWH generated increased 33.3% primarily as a result of increases in commodity and transportation costs. The average cost of natural gas per KWH generated decreased 25.1% primarily as a result of decreases in commodity prices.

36

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Non-Affiliates

In the first quarter 2009, purchased power expense from non-affiliates was $15.5 million compared to $11.2 million for the same period in 2008. This increase was primarily related to a 37.8% volume increase in KWHs purchased from available lower-priced market energy alternatives.

Energy purchases from non-affiliates will vary depending on the market cost of available energy being lower than the cost of Southern Company system-generated energy, demand for energy within the Southern Company system service territory, and availability of Southern Company system generation.

Affiliates

In the first quarter 2009, purchased power expense from affiliates was $41.6 million compared to $88.7 million for the same period in 2008. This decrease was primarily related to a 57.5% decrease in the amount of energy purchased because of the availability of lower-priced market energy alternatives, partially offset by a 10.4% increase in price.

Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC, as approved by the FERC.

Other Operations and Maintenance Expenses

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(32.7)	(10.6)

In the first quarter 2009, other operations and maintenance expenses were $276.8 million compared to $309.5 million for the same period in 2008. This decrease was primarily a result of a $35.9 million decrease in steam power expense associated with fewer scheduled outages, primarily offset by a $5.0 million increase in nuclear production expense related to operations and scheduled outage cost.

Depreciation and Amortization

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$18.8	15.1

For the first quarter 2009, depreciation and amortization was $143.4 million compared to $124.6 million for the same period in 2008. This increase was the result of an increase in plant in service due to additions to property, plant, and equipment primarily related to steam power, environmental mandates, and transmission projects. See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Depreciation and Amortization” of Alabama Power in Item 7 of the Form 10-K for additional information.

37

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Allowance for Equity Funds Used During Construction

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$5.4	48.0

For the first quarter 2009, allowance for equity funds used during construction (AFUDC) was $16.7 million compared to $11.3 million for the same period in 2008. This increase was primarily due to increases in the amount of construction work in progress at generating facilities related to environmental mandates.

Income Taxes

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$11.6	15.8

For the first quarter 2009, income taxes were $85.0 million compared to $73.4 million for the same period in 2008. This increase was primarily due to higher pre-tax income and a decrease in the tax benefit from the production activities deduction, partially offset by the increase in non-taxable AFUDC and a decrease in expense related to tax contingencies.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Alabama Power’s future earnings potential. The level of Alabama Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power’s primary business of selling electricity. These factors include Alabama Power’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power’s service area. Recent recessionary conditions have negatively impacted sales growth and are expected to continue to have a negative impact on energy sales, particularly to industrial customers. The timing and extent of the economic recovery will impact future earnings.

For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Alabama Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 17, 2009, the EPA released a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. The ultimate outcome of the proposed endangerment finding cannot be determined at this time and will depend on additional regulatory action and potential legal challenges. However, regulatory decisions that may follow from such a finding could have implications for both new and existing stationary sources, such as power plants. In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Alabama Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

FERC and Alabama PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence

39

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. Implementation of the energy auction in accordance with the MBR tariff order is expected to adequately mitigate going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Fuel Cost Recovery” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for information regarding Alabama Power’s fuel cost recovery. Alabama Power’s under recovered fuel costs as of March 31, 2009 totaled $189.0 million as compared to $305.8 million at December 31, 2008. These under recovered fuel costs at March 31, 2009 are included in under recovered regulatory clause revenues on Alabama Power’s Condensed Balance Sheets herein. This classification is based on an estimate which includes 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 the recovery of the under recovered fuel costs.

Rate ECR revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates.

Natural Disaster Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Natural Disaster Cost Recovery” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Natural Disaster Cost Recovery” in Item 8 of the Form 10-K for information regarding natural disaster cost recovery. At March 31, 2009, Alabama Power had accumulated a balance of $37.1 million in the target reserve for future storms, which is included in the Condensed Balance Sheets herein under “Other Regulatory Liabilities.”

Steam Service

On February 5, 2009, the Alabama PSC granted a Certificate of Abandonment of Steam Service in the downtown area of the City of Birmingham. The order allows Alabama Power to discontinue steam service by the earlier of three years from May 14, 2008 or when it has no remaining steam service customers. Currently, Alabama Power has contractual obligations to provide steam service until 2013. Impacts related to the abandonment of steam service are recognized in operating income and are not material to the earnings of Alabama Power.

Income Tax Matters

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Alabama Power. Alabama Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $75 million and $90 million. Alabama

40

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Power is currently assessing the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Other Matters

Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power’s business activities are subject to extensive governmental regulation related to public health and the environment. 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 opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against Alabama Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Alabama Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Alabama Power’s financial statements.

See the Notes to the Condensed Financial Statements herein for 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

Alabama Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, and Unbilled Revenues.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Alabama Power’s financial condition remained stable at March 31, 2009. Throughout the recent turmoil in the financial markets, Alabama Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper programs and variable rate pollution control revenue bonds. Alabama Power has continued to issue commercial paper at reasonable rates. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit have increased, and Alabama Power has been and expects to continue to be subject to higher costs as its existing

41

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

facilities are replaced or renewed. Total committed credit fees average less than ¹/4 of 1% per year for Alabama Power. Alabama Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of the financial turmoil cannot be determined at this time. Alabama Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

Alabama Power’s investments in pension and nuclear decommissioning trust funds have continued to decline in value during the first quarter 2009. Alabama Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2011 and such contribution could be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time. Alabama Power does not expect any changes to the funding obligations to the nuclear decommissioning trust at this time.

Net cash provided from operating activities totaled $296.9 million for the first three months of 2009, compared to $142.2 million for the corresponding period in 2008. Significant changes in operating cash flow for the first three months of 2009 include a lower receivables balance from increased collections and lower cash outflows for fossil fuel inventory as compared to the first three months of 2008. Net cash used for investing activities totaled $326.5 million primarily due to gross property additions to utility plant of $338.0 million in the first three months of 2009. These additions were primarily related to construction of transmission and distribution facilities, replacement of steam generation equipment, purchases of nuclear fuel, and construction related to environmental mandates. Net cash provided from financing activities totaled $335.3 million for the first three months of 2009, compared to $195.8 million for the corresponding period in 2008. The $139.5 million increase is primarily due to greater issuances of securities and no redemption of securities in the first three months of 2009 as compared to the first three months of 2008. Fluctuations in cash flow from financing activities vary from year-to-year based on capital needs and securities redeemed.

Significant balance sheet changes for the first quarter 2009 include an increase of $305.8 million in cash and cash equivalents primarily due to an increase in temporary cash investments, an increase of $154.3 million in gross plant primarily due to increases in transmission and distribution projects and other production expenses. Long-term debt increased $499.1 million.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power’s capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $250.0 million will be required through March 31, 2010 for maturities of long-term debt. 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; revised load growth estimates; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; Alabama PSC approvals; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

42

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Sources of Capital

Alabama Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Recently, Alabama Power has primarily utilized funds from operating cash flows, unsecured debt, common stock, preferred stock, and preference stock. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Alabama Power in Item 7 of the Form 10-K for additional information.

Alabama Power’s current liabilities sometimes exceed current assets because of Alabama Power’s debt due within one year and the periodic use of short-term debt as a funding source primarily to meet scheduled maturities of long-term debt as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Alabama Power had at March 31, 2009 cash and cash equivalents of approximately $334 million, unused committed lines of credit of approximately $1.3 billion (including $582 million of such lines which are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds), and commercial paper programs. Of the unused credit facilities, $466 million will expire in 2009, $25 million will expire in 2011, and $765 million will expire in 2012. Of the facilities that expire in 2009, $379 million allow for one-year term loans. Alabama Power expects to renew its credit facilities, as needed, prior to expiration. See Note 6 to the financial statements of Alabama Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and other Southern Company subsidiaries. At March 31, 2009, Alabama Power had no commercial paper outstanding and no outstanding borrowings under its committed lines of credit. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Credit Rating Risk

Alabama Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are primarily for fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At March 31, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $4 million. At March 31, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $203 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. In addition, certain nuclear fuel agreements could require collateral of up to $64 million in the event of a rating change to below investment grade for Southern Company. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Alabama Power’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

Alabama Power’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Alabama Power is not aware of any facts or circumstances that would significantly affect exposures on

43

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation, Alabama Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Alabama Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Alabama Power continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. As such, Alabama Power has no material change in market risk exposure when compared with the December 31, 2008 reporting period.

The changes in fair value of energy-related derivative contracts for the three months ended March 31, 2009 were as follows:

	First Quarter
	2009
	Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(91.9	)
Contracts realized or settled		23.2
Current period changes(a)		(61.5	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(130.2	)

(a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

The decrease in the fair value positions of the energy-related derivative contracts for the three months ended March 31, 2009 was $38 million, substantially all of which is due to natural gas positions. This change is attributable to both the volume and prices of natural gas. At March 31, 2009, Alabama Power had a net hedge volume of 49.3 Bcf with a weighted average contract cost approximately $2.70 per mmBtu above market prices, compared to 44.5 Bcf at December 31, 2008 with a weighted average contract cost approximately $2.12 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the fuel cost recovery clause.

At March 31, 2009, the fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:

	March 31, 2009
	(in millions)
Regulatory hedges	$	(130.2	)
Cash flow hedges		—
Not designated		—
-
Total fair value	$	(130.2	)

Energy-related derivative contracts which are designated as regulatory hedges relate to Alabama Power’s fuel hedging program where 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 fuel cost recovery clauses. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in other comprehensive income 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.

44

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Unrealized pre-tax gains and losses recognized in income for the three months ended March 31, 2009 and 2008 for energy-related derivative contracts that are not hedges were not material.

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2009 are as follows:

	March 31, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(130.2	)		(105.4	)		(24.8	)		—
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(130.2	)	$	(105.4	)	$	(24.8	)	$	—

Alabama Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Alabama Power in Item 7 and Notes 1 and 6 to the financial statements of Alabama Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein.

Financing Activities

In March 2009, Alabama Power issued $500 million of Series 2009A 6.00% Senior Notes due March 1, 2039. The proceeds were used to repay short-term indebtedness and for other general corporate purposes, including Alabama Power’s continuous construction program.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Alabama Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

45

GEORGIA POWER COMPANY

46

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009			2008
	(in thousands)
Operating Revenues:
Retail revenues	$	1,592,395		$	1,575,007
Wholesale revenues —
Non-affiliates		95,986			152,692
Affiliates		15,210			73,910
Other revenues		62,250			63,238
Total operating revenues		1,765,841			1,864,847
Operating Expenses:
Fuel		600,490			637,923
Purchased power —
Non-affiliates		61,953			58,031
Affiliates		197,223			252,935
Other operations and maintenance		390,493			368,815
Depreciation and amortization		167,111			150,608
Taxes other than income taxes		76,248			71,286
Total operating expenses		1,493,518			1,539,598
Operating Income		272,323			325,249
Other Income and (Expense):
Allowance for equity funds used during construction		20,754			27,757
Interest income		1,230			787
Interest expense, net of amounts capitalized		(98,390	)		(86,338	)
Other income (expense), net		(6,720	)		(3,293	)
Total other income and (expense)		(83,126	)		(61,087	)
Earnings Before Income Taxes		189,197			264,162
Income taxes		62,628			83,801
Net Income		126,569			180,361
Dividends on Preferred and Preference Stock		4,345			4,345
Net Income After Dividends on Preferred and Preference Stock	$	122,224		$	176,016

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009		2008
	(in thousands)
Net Income After Dividends on Preferred and Preference Stock	$	122,224	$	176,016
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $1,180 and $(6,043), respectively		1,870		(9,580	)
Reclassification adjustment for amounts included in net income, net of tax of $1,743 and $206, respectively		2,763		327
Total other comprehensive income (loss)		4,633		(9,253	)
COMPREHENSIVE INCOME	$	126,857	$	166,763

The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

47

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	126,569		$	180,361
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization		199,773			178,735
Deferred income taxes and investment tax credits		(7,130	)		(5,709	)
Deferred revenues		(7,685	)		35,046
Deferred expenses		26,387			27,996
Allowance for equity funds used during construction		(20,754	)		(27,757	)
Pension, postretirement, and other employee benefits		(386	)		9,863
Hedge settlements		(16,167	)		(15,816	)
Other, net		26,708			(25,593	)
Changes in certain current assets and liabilities —
Receivables		13,563			77,074
Fossil fuel stock		(112,255	)		1,293
Prepaid income taxes		(5,139	)		22,380
Other current assets		4,562			(4,042	)
Accounts payable		174,347			(44,570	)
Accrued taxes		(135,100	)		(79,097	)
Accrued compensation		(96,144	)		(72,174	)
Other current liabilities		61,917			22,630
Net cash provided from operating activities		233,066			280,620
Investing Activities:
Property additions		(640,486	)		(517,606	)
Distribution of restricted cash from pollution control revenue bonds		9,305			16,094
Nuclear decommissioning trust fund purchases		(318,732	)		(113,811	)
Nuclear decommissioning trust fund sales		320,681			106,931
Cost of removal, net of salvage		(16,368	)		(11,346	)
Change in construction payables, net of joint owner portion		55,767			8,608
Other		14,125			(11,239	)
Net cash used for investing activities		(575,708	)		(522,369	)
Financing Activities:
Decrease in notes payable, net		(76,509	)		(359,113	)
Proceeds —
Capital contributions from parent company		280,016			241,800
Senior notes		500,000			250,000
Other long-term debt		750			300,000
Redemptions —
Senior notes		(150,361	)		(417	)
Payment of preferred and preference stock dividends		(4,413	)		(3,947	)
Payment of common stock dividends		(184,725	)		(180,300	)
Other		(7,554	)		(3,313	)
Net cash provided from financing activities		357,204			244,710
Net Change in Cash and Cash Equivalents		14,562			2,961
Cash and Cash Equivalents at Beginning of Period		132,739			15,392
Cash and Cash Equivalents at End of Period	$	147,301		$	18,353
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $9,143 and $11,837 capitalized for 2009 and 2008, respectively)	$	60,905		$	70,452
Income taxes (net of refunds)	$	13,330		$	450

The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At March 31,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	147,301		$	132,739
Restricted cash and cash equivalents		15,879			22,381
Receivables —
Customer accounts receivable		505,440			554,219
Unbilled revenues		131,520			147,978
Under recovered regulatory clause revenues		351,964			338,780
Other accounts and notes receivable		228,555			97,899
Affiliated companies		20,874			13,091
Accumulated provision for uncollectible accounts		(11,291	)		(10,732	)
Fossil fuel stock, at average cost		597,012			484,757
Materials and supplies, at average cost		361,226			356,537
Vacation pay		65,390			71,217
Prepaid income taxes		71,126			65,987
Other regulatory assets		164,748			118,961
Other		45,489			63,464
Total current assets		2,695,233			2,457,278
Property, Plant, and Equipment:
In service		24,266,916			23,975,262
Less accumulated provision for depreciation		9,204,865			9,101,474
		15,062,051			14,873,788
Nuclear fuel, at amortized cost		292,163			278,412
Construction work in progress		1,773,995			1,434,989
Total property, plant, and equipment		17,128,209			16,587,189
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		57,796			57,163
Nuclear decommissioning trusts, at fair value		432,575			460,430
Other		37,970			40,945
Total other property and investments		528,341			558,538
Deferred Charges and Other Assets:
Deferred charges related to income taxes		578,218			572,528
Deferred under recovered regulatory clause revenues		366,045			425,609
Other regulatory assets		1,435,775			1,449,352
Other		205,278			265,174
Total deferred charges and other assets		2,585,316			2,712,663
Total Assets	$	22,937,099		$	22,315,668

The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At March 31,			At December 31,
Liabilities and Stockholder’s Equity	2009			2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	380,323		$	280,443
Notes payable		280,586			357,095
Accounts payable —
Affiliated		195,395			260,545
Other		748,629			422,485
Customer deposits		191,356			186,919
Accrued taxes —
Income taxes		102,591			70,916
Unrecognized tax benefits		141,095			128,712
Other		91,672			278,172
Accrued interest		107,411			79,432
Accrued vacation pay		51,563			57,643
Accrued compensation		43,734			135,191
Liabilities from risk management activities		143,271			113,432
Other		186,851			136,176
Total current liabilities		2,664,477			2,507,161
Long-term Debt		7,254,092			7,006,275
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		3,076,923			3,064,580
Deferred credits related to income taxes		136,630			140,933
Accumulated deferred investment tax credits		252,788			256,218
Employee benefit obligations		882,380			882,965
Asset retirement obligations		696,930			688,019
Other cost of removal obligations		385,140			396,947
Other regulatory liabilities		97,502			115,865
Other		119,370			111,505
Total deferred credits and other liabilities		5,647,663			5,657,032
Total Liabilities		15,566,232			15,170,468
Preferred and Preference Stock		265,957			265,957
Common Stockholder’s Equity:
Common stock, without par value—
Authorized - 20,000,000 shares
Outstanding - 9,261,500 shares		398,473			398,473
Paid-in capital		3,939,265			3,655,731
Retained earnings		2,795,289			2,857,789
Accumulated other comprehensive loss		(28,117	)		(32,750	)
Total common stockholder’s equity		7,104,910			6,879,243
Total Liabilities and Stockholder’s Equity	$	22,937,099		$	22,315,668

The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY

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

FIRST QUARTER 2009 vs. FIRST QUARTER 2008

OVERVIEW

Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Georgia Power’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain energy sales in the midst of the current economic downturn, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, and fuel prices. Appropriately balancing the need to recover these increasing costs with customer prices will continue to challenge Georgia Power for the foreseeable future. Georgia Power is required to file a general rate case by July 1, 2010, which will determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued. Georgia Power also expects to file a fuel cost recovery case in the third quarter 2009.

Georgia Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Georgia Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(53.8)	(30.6)

Georgia Power’s net income after dividends on preferred and preference stock for the first quarter 2009 was $122.2 million compared to $176.0 million for the corresponding period in 2008. The decrease was primarily due to lower industrial base revenues resulting from the recessionary economy and a charge in the first quarter 2009 in connection with a voluntary attrition plan under which 579 employees elected to resign from their positions effective March 31, 2009.

Retail Revenues

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$17.4	1.1

In the first quarter 2009, retail revenues were $1.59 billion compared to $1.57 billion for the corresponding period in 2008.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the change to retail revenues are as follows:

	First Quarter
	2009
	(in millions)			(% change)
Retail – prior year	$	1,575.0
Estimated change in —
Rates and pricing		19.7			1.3
Sales growth (decline)		(18.1	)		(1.2	)
Weather		(0.6	)		—
Fuel cost recovery		16.4			1.0
Retail – current year	$	1,592.4			1.1	%

Revenues associated with changes in rates and pricing increased in the first quarter 2009 when compared to the corresponding period in 2008 due to increased environmental compliance cost recovery revenues of $49.4 million in accordance with the 2007 Retail Rate Plan, partially offset by decreased revenues from market-response rates to large commercial and industrial customers.

Revenues attributable to changes in sales growth declined in the first quarter 2009 when compared to the corresponding period for 2008. This decrease was primarily due to the recessionary economy, partially offset by a 0.4% increase in retail customers. Weather-adjusted residential KWH sales increased 1.3%, weather-adjusted commercial KWH sales decreased 0.6%, and weather-adjusted industrial KWH sales decreased 13.9% for the first quarter 2009 when compared to the corresponding period in 2008. Weather-adjusted industrial KWH sales decreased due to a broad decline in demand across all industrial segments.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased by $16.4 million in the first quarter 2009 when compared to the corresponding period in 2008 due to a higher proportion of retail fuel revenues compared to wholesale fuel revenues during the period, partially offset by decreased fuel and purchased power expenses. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.

Wholesale Revenues – Non-Affiliates

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(56.7)	(37.1)

Wholesale revenues from non-affiliates will vary depending on the market cost of available energy compared to the cost of Georgia Power and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and the availability of Southern Company system generation. In the first quarter 2009, wholesale revenues from non-affiliates were $96.0 million compared to $152.7 million in the same period in 2008. This decrease was due to a 53.1% decrease in KWH sales due to lower demand.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Affiliates

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(58.7)	(79.4)

Wholesale revenues from affiliated companies will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost. In the first quarter 2009, wholesale revenues from affiliates were $15.2 million compared to $73.9 million in the same period in 2008. This decrease was due to an 83.6% decrease in KWH sales due to lower demand primarily caused by the recessionary economy.

Fuel and Purchased Power Expenses

	First Quarter 2009 vs. First Quarter 2008
	(change in millions)			(% change)
Fuel	$	(37.4	)		(5.9	)
Purchased power – non-affiliates		3.9			6.8
Purchased power – affiliates		(55.7	)		(22.0	)
Total fuel and purchased power expenses	$	(89.2	)

In the first quarter 2009, total fuel and purchased power expenses were $859.7 million compared to $948.9 million in the same period in 2008. This decrease was due to a $104.8 million decrease related to fewer KWHs generated and purchased, partially offset by a $15.6 million net increase in the average cost of fuel and purchased power.

Details of Georgia Power’s cost of generation and purchased power are as follows:

	First Quarter		First Quarter		Percent
Average Cost	2009		2008		Change
	(cents per net KWH)
Fuel		3.23		2.84		13.7
Purchased power		6.40		7.32		(12.6	)

In the first quarter 2009, fuel expense was $600.5 million compared to $637.9 million in the same period in 2008. This decrease was due to an 18.2% decrease in volume of KWHs generated primarily as a result of the lower KWH demand and lower natural gas prices, partially offset by a 28.8% increase in the average cost of coal per KWH generated.

Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Georgia Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – “FERC and Georgia PSC Matters – Retail Fuel Cost Recovery” herein for additional information.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Non-Affiliates

In the first quarter 2009, purchased power expense from non-affiliates was $62.0 million compared to $58.0 million in the same period in 2008. This increase was due to a 45.9% volume increase in KWHs purchased from available lower-priced market energy alternatives partially offset by a 26.9% decrease in the average cost per KWH purchased.

Energy purchases from non-affiliates will vary depending on the market cost of available energy being lower than Southern Company system-generated energy, demand for energy within the Southern Company system service territory, and availability of Southern Company system generation.

Affiliates

In the first quarter 2009, purchased power expense from affiliates was $197.2 million compared to $252.9 million in the same period in 2008. This decrease was due to a 9.5% decrease in the average cost per KWH purchased and a 7.6% volume decrease in KWHs purchased because of the availability of lower-priced market energy alternatives within the Power Pool.

Energy purchases from affiliated companies will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC, as approved by the FERC.

Other Operations and Maintenance Expenses

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$21.7	5.9

In the first quarter 2009, other operations and maintenance expenses were $390.5 million compared to $368.8 million in the same period in 2008. This increase was primarily due to a $29.4 million charge in the first quarter 2009 in connection with a voluntary attrition plan under which 579 employees elected to resign their positions effective March 31, 2009. The first quarter 2009 charge will be largely offset by lower salary costs for the remainder of the year and is not expected to have a material impact on Georgia Power’s financial statements for the year ending December 31, 2009. This increase was partially offset by an $8.5 million decrease in fossil and distribution maintenance as a result of the timing of maintenance activities.

Depreciation and Amortization

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$16.5	11.0

In the first quarter 2009, depreciation and amortization was $167.1 million compared to $150.6 million in the same period in 2008. This increase was due primarily to additional plant in service related to completed transmission, distribution, and environmental projects.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Allowance for Equity Funds Used During Construction

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(7.0)	(25.2)

In the first quarter 2009, allowance for equity funds used during construction was $20.8 million compared to $27.8 million in the same period in 2008. This decrease was primarily due to a decrease in the average construction work in progress balances in the first quarter 2009 compared to the same period in 2008 as a result of projects completed during 2008.

Taxes Other Than Income Taxes

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$4.9	7.0

In the first quarter 2009, taxes other than income taxes were $76.2 million compared to $71.3 million in the same period in 2008. This increase is primarily due to increased ad valorem taxes.

Income Taxes

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(21.2)	(25.3)

In the first quarter 2009, income taxes were $62.6 million compared to $83.8 million in the same period in 2008. This decrease was primarily due to lower pre-tax net income.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Georgia Power’s future earnings potential. The level of Georgia Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power’s business of selling electricity. These factors include Georgia Power’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power’s service area. Recent recessionary conditions have negatively impacted sales growth and are expected to continue to have a negative impact on energy sales, particularly to industrial customers. The timing and extent of the economic recovery will impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Georgia Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 17, 2009, the EPA released a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. The ultimate outcome of the proposed endangerment finding cannot be determined at this time and will depend on additional regulatory action and potential legal challenges. However, regulatory decisions that may follow from such a finding could have implications for both new and existing stationary sources, such as power plants. In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Georgia Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

FERC and Georgia PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. Implementation of the energy auction in accordance with the MBR tariff order is expected to adequately mitigate going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information. In May 2008, the Georgia PSC approved an additional increase of approximately $222 million effective June 2008. On March 10, 2009, the Georgia PSC granted Georgia Power’s request to delay its fuel case filing until September 4, 2009. The extension was requested as a result of difficulty in establishing a forward-looking fuel rate due to volatile coal and gas prices, uncertain sales forecasts, and a continuing decline in the State of Georgia’s economy. New fuel rates are expected to become effective January 1, 2010. As of March 31, 2009, Georgia Power had a total under recovered fuel cost balance of approximately $718 million compared to $764 million at December 31, 2008.

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, any changes in the billing factor will not have a significant effect on Georgia Power’s revenues or net income, but will affect cash flow.

Income Tax Matters

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Georgia Power. Georgia Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $120 million and $150 million. Georgia Power is currently assessing the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Construction

Nuclear

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Nuclear – Construction” of Georgia Power in Item 7 of the Form 10-K for information regarding the potential expansion of Plant Vogtle.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On March 17, 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 at an in-service cost of $6.4 billion. In addition, the Georgia PSC voted to approve inclusion of the related construction work in progress accounts in rate base and to recover financing costs during the construction period beginning in 2011.

On April 21, 2009, the Governor of the State of Georgia signed into law The Georgia Nuclear Energy Financing Act that will allow Georgia Power to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period. The cost recovery provisions will become effective January 1, 2011.

Other

On March 17, 2009, the Georgia PSC approved Georgia Power’s request to convert Plant Mitchell from coal-fueled to wood biomass-fueled at an in-service cost of approximately $103 million. The conversion is expected to be completed in 2012. The Georgia PSC also approved Georgia Power’s plan to install additional environmental controls at Plants Branch and Yates.

Other Matters

Georgia Power is involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power’s business activities are subject to extensive governmental regulation related to public health and the environment. 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 opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Georgia Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Georgia Power’s financial statements.

See the Notes to the Condensed Financial Statements herein for 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

Georgia Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, and Unbilled Revenues.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FINANCIAL CONDITION AND LIQUIDITY

Overview

Georgia Power’s financial condition remained stable at March 31, 2009. Throughout the recent turmoil in the financial markets, Georgia Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper programs and variable rate pollution control revenue bonds. Georgia Power has continued to issue commercial paper at reasonable rates. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit have increased, and Georgia Power has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. Of the $185 million of facilities expiring in the first quarter 2009, $130 million were replaced or renewed. Subsequent to March 31, 2009, Georgia Power entered into additional credit agreements totaling $425 million. Total committed credit fees at Georgia Power average less than ³/₈ of 1% per year. Georgia Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined. The ultimate impact on future financing costs as a result of the financial turmoil cannot be determined at this time. Georgia Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

Georgia Power’s investments in pension and nuclear decommissioning trust funds have continued to decline in value during the first quarter 2009. Georgia Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2011 and such contribution could be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time. Georgia Power does not expect any changes to funding obligations to the nuclear decommissioning trusts prior to 2011.

Net cash provided from operating activities totaled $233.1 million for the first three months of 2009, compared to $280.6 million for the corresponding period in 2008. The $47.5 million decrease in cash provided from operating activities in the first three months of 2009 is primarily due to a decrease in net income and higher fuel and materials inventory additions. Net cash used for investing activities totaled $575.7 million primarily due to gross property additions to utility plant in the first three months of 2009. Net cash provided from financing activities totaled $357.2 million for the first three months of 2009, compared to $244.7 million for the corresponding period in 2008. The $112.5 million increase is primarily due to higher capital contributions from Southern Company and a smaller decrease in short-term debt compared to the corresponding period in 2008.

Significant balance sheet changes for the first three months of 2009 include an increase of $541.0 million in total property, plant, and equipment and an increase of $247.8 million in long-term debt to replace short-term debt and provide funds for Georgia Power’s continuous construction program.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power’s capital requirements for its construction program, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $380.3 million will be required through March 31, 2010 to fund maturities of long-term debt. 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; revised load growth estimates; changes in environmental statutes and regulations; changes in nuclear plants to meet new

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Recently, Georgia Power has primarily utilized funds from operating cash flows, short-term debt, security issuances, term-loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Georgia Power in Item 7 of the Form 10-K for additional information.

Georgia Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Georgia Power had at March 31, 2009 approximately $147.3 million of cash and cash equivalents and approximately $1.3 billion of unused credit arrangements with banks. See Note 6 to the financial statements of Georgia Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Of the unused credit arrangements in place at March 31, 2009, $40 million expire in 2009, $130 million expire in 2010, and $1.1 billion expire in 2012. As described above, Georgia Power entered into additional credit agreements totaling $425 million subsequent to March 31, 2009. These facilities all expire in 2010. Of the facilities that expire in 2009 and 2010, $40 million contain provisions allowing two-year term loans executable at expiration. Georgia Power expects to renew its credit facilities, as needed, prior to expiration.

Credit arrangements provide liquidity support to Georgia Power’s commercial paper program and purchase obligations related to variable rate pollution control revenue bonds. Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and other Southern Company subsidiaries. At March 31, 2009, Georgia Power had approximately $179.7 million of commercial paper and $100 million of short-term bank loans outstanding. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Credit Rating Risk

Georgia Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation. At March 31, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $27 million. At March 31, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.0 billion. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. In addition, certain nuclear fuel agreements could require collateral of up to $187 million in the event of a rating change to below investment grade for Southern Company. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit

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

rating downgrade could impact Georgia Power’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

Georgia Power’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Georgia Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation, Georgia Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Georgia Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Georgia Power continues to manage a fuel-hedging program implemented per the guidelines of the Georgia PSC. As such, Georgia Power has no material change in market risk exposure when compared with the December 31, 2008 reporting period.

The changes in fair value of energy-related derivative contracts for the three months ended March 31, 2009 were as follows:

	First Quarter
	2009
	Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(113.2	)
Contracts realized or settled		19.8
Current period changes(a)		(83.2	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(176.6	)

(a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

The decrease in the fair value positions of the energy-related derivative contracts for the three months ended March 31, 2009 was $63 million, substantially all of which is due to natural gas positions. This change is attributable to both the volume and prices of natural gas. At March 31, 2009, Georgia Power had a net hedge volume of 71.5 Bcf with a weighted average contract cost approximately $2.53 per mmBtu above market prices, compared to 59.3 Bcf at December 31, 2008 with a weighted average contract cost approximately $1.96 per mmBtu above market prices. The natural gas hedges are recovered through the fuel cost recovery mechanism.

At March 31, 2009, the fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:

	March 31, 2009
	(in millions)
Regulatory hedges	$	(176.6	)
Not designated		—
Total fair value	$	(176.6	)

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Energy-related derivative contracts which are designated as regulatory hedges relate to Georgia Power’s fuel hedging program where 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 fuel cost recovery mechanism. 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.

Unrealized pre-tax gains and losses recognized in income for the three months ended March 31, 2009 and 2008 for energy-related derivative contracts that are not hedges were not material.

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2009 are as follows:

	March 31, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(176.6	)		(135.8	)		(40.8	)		—
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(176.6	)	$	(135.8	)	$	(40.8	)	$	—

Georgia Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Georgia Power in Item 7 and Notes 1 and 6 to the financial statements of Georgia Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein.

Financing Activities

During the first quarter 2009, Georgia Power issued $500 million of Series 2009A 5.95% Senior Notes due February 1, 2039. The proceeds were used to repay at maturity $150 million aggregate principal amount of Series U Floating Rate Senior Notes due February 7, 2009, to repay a portion of short-term indebtedness, and for general corporate purposes, including Georgia Power’s continuous construction program. Georgia Power settled $100 million of hedges related to the Series 2009A issuance at a loss of approximately $16 million, and this loss will be amortized to interest expense, in earnings, together with a previously settled loss of approximately $2 million, over 10 years.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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GULF POWER COMPANY

63

GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009			2008
	(in thousands)
Operating Revenues:
Retail revenues	$	238,391		$	227,964
Wholesale revenues —
Non-affiliates		21,966			25,656
Affiliates		5,360			42,940
Other revenues		18,567			14,975
Total operating revenues		284,284			311,535
Operating Expenses:
Fuel		115,553			150,127
Purchased power —
Non-affiliates		4,438			3,126
Affiliates		15,381			8,743
Other operations and maintenance		72,491			66,431
Depreciation and amortization		23,059			21,704
Taxes other than income taxes		22,448			20,696
Total operating expenses		253,370			270,827
Operating Income		30,914			40,708
Other Income and (Expense):
Allowance for equity funds used during construction		4,818			1,483
Interest income		209			709
Interest expense, net of amounts capitalized		(9,832	)		(10,996	)
Other income (expense), net		(616	)		(666	)
Total other income and (expense)		(5,421	)		(9,470	)
Earnings Before Income Taxes		25,493			31,238
Income taxes		7,400			10,157
Net Income		18,093			21,081
Dividends on Preference Stock		1,551			1,551
Net Income After Dividends on Preference Stock	$	16,542		$	19,530

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009		2008
	(in thousands)
Net Income After Dividends on Preference Stock	$	16,542	$	19,530
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $- and $(1,481), respectively		—		(2,358	)
Reclassification adjustment for amounts included in net income, net of tax of $105 and $54, respectively		167		87
Total other comprehensive income (loss)		167		(2,271	)
COMPREHENSIVE INCOME	$	16,709	$	17,259

The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	18,093		$	21,081
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization		24,269			22,981
Deferred income taxes		(4,022	)		569
Allowance for equity funds used during construction		(4,818	)		(1,483	)
Pension, postretirement, and other employee benefits		(391	)		1,319
Stock option expense		479			408
Tax benefit of stock options		3			85
Other, net		(5,325	)		430
Changes in certain current assets and liabilities —
Receivables		32,887			11,189
Fossil fuel stock		(18,231	)		(13,622	)
Materials and supplies		(205	)		(1,005	)
Prepaid income taxes		416			—
Property damage cost recovery		5,428			5,742
Other current assets		916			1,063
Accounts payable		(13,344	)		(1,438	)
Accrued taxes		6,361			6,094
Accrued compensation		(11,576	)		(9,847	)
Other current liabilities		5,761			6,230
Net cash provided from operating activities		36,701			49,796
Investing Activities:
Property additions		(109,737	)		(76,305	)
Investment in restricted cash from pollution control revenue bonds		(49,188	)		—
Cost of removal, net of salvage		(2,330	)		(3,583	)
Contruction payables		2,362			1,014
Other		(1,578	)		(54	)
Net cash used for investing activities		(160,471	)		(78,928	)
Financing Activities:
Decrease in notes payable, net		(89,930	)		(21,413	)
Proceeds —
Common stock issued to parent		135,000			—
Capital contributions from parent company		1,106			72,106
Gross excess tax benefit of stock options		9			194
Pollution control revenue bonds		130,400			—
Payment of preference stock dividends		(1,551	)		(1,406	)
Payment of common stock dividends		(22,350	)		(20,425	)
Other		(847	)		(271	)
Net cash provided from financing activities		151,837			28,785
Net Change in Cash and Cash Equivalents		28,067			(347	)
Cash and Cash Equivalents at Beginning of Period		3,443			5,348
Cash and Cash Equivalents at End of Period	$	31,510		$	5,001
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $1,920 and $654 capitalized for 2009 and 2008, respectively)	$	8,347		$	8,241
Income taxes (net of refunds)	$	3,281		$	1,200

The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At March 31,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	31,510		$	3,443
Restricted cash and cash equivalents		49,188			—
Receivables —
Customer accounts receivable		67,112			69,531
Unbilled revenues		42,597			48,742
Under recovered regulatory clause revenues		78,850			98,644
Other accounts and notes receivable		10,300			7,201
Affiliated companies		1,015			8,516
Accumulated provision for uncollectible accounts		(1,557	)		(2,188	)
Fossil fuel stock, at average cost		126,352			108,129
Materials and supplies, at average cost		37,041			36,836
Other regulatory assets		48,058			38,908
Other		24,030			25,655
Total current assets		514,496			443,417
Property, Plant, and Equipment:
In service		2,835,502			2,785,561
Less accumulated provision for depreciation		982,542			971,464
		1,852,960			1,814,097
Construction work in progress		453,749			391,987
Total property, plant, and equipment		2,306,709			2,206,084
Other Property and Investments		15,904			15,918
Deferred Charges and Other Assets:
Deferred charges related to income taxes		27,888			24,220
Other regulatory assets		174,115			170,836
Other		19,945			18,550
Total deferred charges and other assets		221,948			213,606
Total Assets	$	3,059,057		$	2,879,025

The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)

	At March 31,			At December 31,
Liabilities and Stockholder’s Equity	2009			2008
	(in thousands)
Current Liabilities:
Pollution control revenue bonds	$	9,930		$	—
Notes payable		58,309			148,239
Accounts payable —
Affiliated		35,822			50,304
Other		94,762			90,381
Customer deposits		29,371			28,017
Accrued taxes —
Income taxes		36,718			39,983
Other		10,504			11,855
Accrued interest		11,113			8,959
Accrued compensation		4,346			15,667
Other regulatory liabilities		12,199			4,602
Liabilities from risk management activities		35,309			26,928
Other		22,603			29,047
Total current liabilities		360,986			453,982
Long-term Debt		969,843			849,265
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		265,516			254,354
Accumulated deferred investment tax credits		10,855			11,255
Employee benefit obligations		96,436			97,389
Other cost of removal obligations		183,002			180,325
Other regulatory liabilities		34,367			28,597
Other		86,981			83,768
Total deferred credits and other liabilities		677,157			655,688
Total Liabilities		2,007,986			1,958,935
Preference Stock		97,998			97,998
Common Stockholder’s Equity:
Common stock, without par value—
Authorized - 20,000,000 shares
Outstanding - March 31, 2009: 3,142,717 shares
- December 31, 2008: 1,792,717 shares		253,060			118,060
Paid-in capital		513,143			511,547
Retained earnings		191,635			197,417
Accumulated other comprehensive loss		(4,765	)		(4,932	)
Total common stockholder’s equity		953,073			822,092
Total Liabilities and Stockholder’s Equity	$	3,059,057		$	2,879,025

The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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GULF POWER COMPANY

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

FIRST QUARTER 2009 vs. FIRST QUARTER 2008

OVERVIEW

Gulf Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in northwest Florida and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Gulf Power’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain energy sales in the midst of the current economic downturn, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel prices, and storm restoration costs. Appropriately balancing the need to recover these increasing costs with customer prices will continue to challenge Gulf Power for the foreseeable future.

Gulf Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS — OVERVIEW — “Key Performance Indicators” of Gulf Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(3.0)	(15.3)

Gulf Power’s net income after dividends on preference stock for the first quarter 2009 was $16.5 million compared to $19.5 million for the corresponding period in 2008. The decrease was primarily due to a decline in sales growth, less favorable weather, and increased other operations and maintenance expenses, partially offset by increased allowance for equity funds used during construction (AFUDC).

Retail Revenues

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$10.4	4.6

In the first quarter 2009, retail revenues were $238.4 million compared to $228.0 million for the corresponding period in 2008.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the change to retail revenues are as follows:

	First Quarter
	2009
	(in millions)			(% change)
Retail – prior year	$	228.0
Estimated change in —
Rates and pricing		7.4			3.2
Sales growth (decline)		(4.1	)		(1.8	)
Weather		(1.6	)		(0.7	)
Fuel and other cost recovery		8.7			3.8
Retail – current year	$	238.4			4.5	%

Revenues associated with changes in rates and pricing increased in the first quarter 2009 when compared to the same period in 2008 primarily due to increased revenue associated with higher projected environmental compliance costs in 2009. Annually, Gulf Power petitions the Florida PSC for recovery of projected costs including any true-up amount from prior periods, and approved rates are implemented each January. These recovery provisions include related expenses and a return on average net investment. See Note 1 to the financial statements of Gulf Power under “Revenues” and Note 3 to the financial statements of Gulf Power under “Environmental Remediation” and “Retail Regulatory Matters – Environmental Cost Recovery” in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales growth declined in the first quarter 2009 when compared to the same period in 2008. Weather-adjusted KWH energy sales to residential and commercial customers decreased 3.0% and 4.1%, respectively, due to decreased customer usage driven by the recession. KWH energy sales to industrial customers decreased 20.1% as a result of recessionary economic conditions and increased customer co-generation due to the lower cost of natural gas.

Revenues attributable to changes in weather decreased in the first quarter 2009 when compared to the corresponding period for 2008 due to less favorable weather.

Fuel and other cost recovery revenues increased in the first quarter 2009 when compared to the corresponding period for 2008 primarily due to higher projected fuel and purchased power costs. Fuel and other cost recovery revenues include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and revenues related to the recovery of storm damage restoration costs. Annually, Gulf Power petitions the Florida PSC for recovery of projected fuel and purchased power costs including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions generally equal the related expenses and have no material effect on net income. See FUTURE EARNINGS POTENTIAL – “FERC and Florida PSC Matters - Retail Fuel Cost Recovery” herein and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under “Revenues” and “Property Damage Reserve” and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters – Storm Damage Cost Recovery” and “Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(3.7)	(14.4)

Wholesale revenues from non-affiliates will vary depending on the market cost of available energy compared to the cost of Gulf Power and Southern Company system owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation. Wholesale revenues from non-affiliates are predominantly unit power sales under long-term contracts to other Florida utilities. Revenues from these contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost.

In the first quarter 2009, wholesale revenues from non-affiliates were $22.0 million compared to $25.7 million for the corresponding period in 2008. The decrease was primarily a result of lower energy revenues related to a 25.1% decrease in KWH sales.

Wholesale Revenues – Affiliates

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(37.6)	(87.5)

Wholesale revenues from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost.

In the first quarter 2009, wholesale revenues from affiliates were $5.3 million compared to $42.9 million for the corresponding period in 2008. The decrease was due to reduced customer demand resulting in an 85.5% decrease in KWH sales and a 13.8% decrease in price resulting from lower Power Pool interchange energy rates.

Other Revenues

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$3.6	24.0

In the first quarter 2009, other revenues were $18.6 million compared to $15.0 million for the corresponding period in 2008. The increase was primarily due to other energy services. The increased revenues from other energy services did not have a material impact on earnings since they were generally offset by associated expenses.

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

Fuel and Purchased Power Expenses

	First Quarter 2009 vs. First Quarter 2008
	(change in millions)			(% change)
Fuel	$	(34.5	)		(23.0	)
Purchased power – non-affiliates		1.3			42.0
Purchased power – affiliates		6.6			75.9
Total fuel and purchased power expenses	$	(26.6	)

In the first quarter 2009, total fuel and purchased power expenses were $135.4 million compared to $162.0 million for the corresponding period in 2008. The net decrease in fuel and purchased power expenses was due to a $48.1 million decrease related to KWHs generated and a $5.8 million decrease in the average cost of purchased power, partially offset by a $13.7 million increase related to KWHs purchased and a $13.6 million increase in the average cost of fuel.

Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Gulf Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – “FERC and Florida PSC Matters – Retail Fuel Cost Recovery” herein for additional information.

Details of Gulf Power’s cost of generation and purchased power are as follows:

	First Quarter		First Quarter		Percent
Average Cost	2009		2008		Change
	(cents per net KWH)
Fuel		4.31		3.80		13.4
Purchased power		5.19		6.70		(22.5	)

In the first quarter 2009, fuel expense was $115.6 million compared to $150.1 million in the same period in 2008. The decrease was due to a $48.1 million decrease related to total KWHs generated, offset by a $13.6 million increase in the average cost of fuel. The average cost of coal per KWH generated increased 20.6% primarily as a result of increases in commodity and transportation costs. The average cost of oil and natural gas per KWH generated decreased 25.9% primarily as a result of decreases in commodity prices.

Non-Affiliates

In the first quarter 2009, purchased power expense from non-affiliates was $4.4 million compared to $3.1 million for the same period in 2008. The increase was due to a $1.6 million increase related to total KWHs purchased, partially offset by a $0.3 million decrease resulting from the lower average cost per KWH.

Energy purchases from non-affiliates will vary depending on the market cost of available energy being lower than Southern Company system-generated energy, demand for energy within the Southern Company system service territory, and the availability of Southern Company system generation.

Affiliates

In the first quarter 2009, purchased power expense from affiliates was $15.3 million compared to $8.7 million for the same period in 2008. The increase was due to a $13.4 million increase related to total KWHs purchased, partially offset by a $6.8 million decrease resulting from the lower average cost per KWH.

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

Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC, as approved by the FERC.

Other Operations and Maintenance Expenses

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$6.1	9.1

In the first quarter 2009, other operations and maintenance expenses were $72.5 million compared to $66.4 million for the corresponding period in 2008. The increase was primarily due to a $4.0 million increase in scheduled maintenance at generation facilities and a $3.0 million increase in other energy services, partially offset by a $0.4 million decrease related to the storm recovery costs associated with previous hurricanes. The increased expenses from other energy services and the decreased storm recovery costs did not have a material impact on earnings since they were offset by increased associated revenues.

Depreciation and Amortization

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$1.4	6.2

For the first quarter 2009, depreciation and amortization was $23.1 million compared to $21.7 million for the corresponding period in 2008. The increase was primarily due to net additions to generation and distribution facilities.

Taxes Other Than Income Taxes

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$1.7	8.5

For the first quarter 2009, taxes other than income taxes were $22.4 million compared to $20.7 million for the corresponding period in 2008. The increase was primarily due to increases in franchise and gross receipts taxes, which were directly related to the increase in retail revenues.

Allowance for Equity Funds Used During Construction

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$3.3	N/M

N/M-Not Meaningful

In the first quarter 2009, allowance for equity funds used during construction was $4.8 million compared to $1.5 million for the corresponding period in 2008. The increase was primarily due to construction of environmental control projects.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Interest Expense, Net of Amounts Capitalized

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(1.2)	(10.6)

In the first quarter 2009, interest expense, net of amounts capitalized was $9.8 million compared to $11.0 million for the corresponding period in 2008. The decrease was primarily the result of an increase in capitalization of AFUDC related to the construction of environmental control projects.

Income Taxes

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(2.8)	(27.1)

In the first quarter 2009, income taxes were $7.4 million compared to $10.2 million for the corresponding period in 2008. The decrease was primarily due to lower earnings before income taxes and an increase in the tax benefit associated with an increase in AFUDC, which is non-taxable, partially offset by a decrease in the federal production activities deduction.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Gulf Power’s future earnings potential. The level of Gulf Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power’s business of selling electricity. These factors include Gulf Power’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Gulf Power’s service area. Recent recessionary conditions have negatively impacted sales growth and are expected to continue to have a negative impact on energy sales, particularly to industrial customers. The timing and extent of the economic recovery will impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Environmental Statutes and Regulations – Water Quality” of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its

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

standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Global Climate Issues” of Gulf Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 17, 2009, the EPA released a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. The ultimate outcome of the proposed endangerment finding cannot be determined at this time and will depend on additional regulatory action and potential legal challenges. However, regulatory decisions that may follow from such a finding could have implications for both new and existing stationary sources, such as power plants. In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Gulf Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

FERC and Florida PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters — Market-Based Rate Authority” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “FERC Matters — Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. Implementation of the energy auction in accordance with the MBR tariff order is expected to adequately mitigate going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Fuel Cost Recovery

Gulf Power has established fuel cost recovery rates approved by the Florida PSC. In recent years, Gulf Power has experienced higher than expected fuel costs for coal and natural gas. If the projected fuel cost over or under recovery balance at year-end exceeds 10% of the projected fuel revenue applicable for the period, Gulf Power is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested.

Under recovered fuel costs at March 31, 2009 totaled $76.9 million, compared to $96.7 million at December 31, 2008. This amount is included in under recovered regulatory clause revenues on Gulf Power’s Condensed Balance Sheets herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any change in the billing factor would have no significant effect on Gulf Power’s revenues or net income, but would affect cash flow. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Gulf Power in Item 7 and Notes 1 and 3 to the financial statements of Gulf Power under “Revenues” and “Retail Regulatory Matters – Fuel Cost Recovery,” respectively, in Item 8 of the Form 10-K for additional information.

Income Tax Matters

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Gulf Power. Gulf Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $13 million and $16 million. Gulf Power is currently assessing the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Other Matters

On March 16, 2009, Gulf Power entered into a PPA (the Agreement) with Shell Energy North America (US), L.P. (Shell). Under the terms of the Agreement, Gulf Power will be entitled to all of the capacity and energy from an approximately 885 MW combined cycle power plant (the Plant) located in Autauga County, Alabama that is owned and operated by Tenaska Alabama II Partners, L.P. (Tenaska). Shell is entitled to all of the capacity and energy from the Plant under a 20-year Energy Conversion Agreement between Shell and Tenaska that expires on May 24, 2023. On April 3, 2009, Gulf Power filed a petition with the Florida PSC requesting approval of the Agreement. The Agreement will commence on the later of June 1, 2009 or the first day of the month following receipt by Gulf Power of a final, non-appealable order of the Florida PSC approving the Agreement. Unless earlier terminated in accordance with its terms, the Agreement will terminate on May 24, 2023. Gulf Power may terminate the Agreement if the Florida PSC approval imposes material qualifications or conditions that are not acceptable to Gulf Power. Payments under the Agreement will be material but are expected to be recovered through Gulf Power’s fuel clause and purchased power capacity clause; therefore, no material impact is expected on Gulf Power’s net income. The ultimate outcome of this matter cannot now be determined.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power’s business activities are subject to extensive governmental regulation related to public health and the environment. 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 opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against Gulf Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Gulf Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Gulf Power’s financial statements.

See the Notes to the Condensed Financial Statements herein for 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

Gulf Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Gulf Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Gulf Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, and Unbilled Revenues.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Gulf Power’s financial condition remained stable at March 31, 2009. Throughout the recent turmoil in the financial markets, Gulf Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper programs and variable rate pollution control revenue bonds. Gulf Power has continued to issue commercial paper at reasonable rates. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit have increased, and Gulf Power has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. In the first quarter 2009, Gulf Power renewed $30 million of expiring credit facilities. In addition, Gulf Power entered into a $20 million facility. Subsequent to March 31, 2009, Gulf Power entered into additional credit arrangements totaling $75 million. Total committed credit fees at Gulf Power average less than ¹/2 of 1% per year. Gulf Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of the financial turmoil cannot be determined at this time. Gulf Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Gulf Power’s investments in pension trust funds have continued to decline in value during the first quarter 2009. Gulf Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2011 and such contribution could be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time.

Net cash provided from operating activities totaled $36.7 million for the first three months of 2009 compared to $49.8 million for the corresponding period in 2008. The $13.1 million decrease in cash provided from operating activities was primarily due to an $18.0 million increase in payments to affiliates related to higher fuel cost; an increase of $4.6 million in the use of funds for fossil fuel inventory; a decrease of $4.6 million in deferred income taxes; and a decrease of $3.0 million in net income, as previously discussed. These changes were partially offset by a decrease of $19.0 million in under recovered regulatory clause revenues related to fuel. Net cash used for investing activities in the first three months of 2009 totaled $160.5 million primarily due to gross property additions to utility plant of $114.9 million and the issuance of pollution control revenue bonds, the proceeds of which are restricted for installation of certain solid waste disposal facilities. These additions were primarily related to installation of equipment to comply with environmental requirements. Net cash provided from financing activities totaled $151.8 million for the first three months of 2009, compared to $28.8 million for the corresponding period in 2008. The $123.0 million increase in cash provided from financing activities was primarily due to the issuances of $135.0 million in common stock and $130.4 million in pollution control revenue bonds in 2009, partially offset by a $68.5 million increase in cash payments related to notes payable and a $71 million decrease in capital contributions from Southern Company.

Significant balance sheet changes for the first quarter 2009 include a net increase of $100.6 million in property, plant, and equipment, primarily related to environmental control projects; the issuance of common stock to Southern Company for $135 million; the issuance of $130.4 million in pollution control revenue bonds, with a related restricted cash balance of $49.2 million; a $19.8 million decrease in under recovered regulatory clause revenues related to fuel; and a $12.0 million change in energy-related derivative contracts.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power’s capital requirements for its construction program, maturities of long-term debt, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements. 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; revised load growth estimates; storm impacts; changes in environmental statutes and regulations; changes in FERC rules and regulations; Florida PSC approvals; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Gulf Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Recently, Gulf Power has utilized funds from operating cash flows, short-term debt, security offerings, a long-term bank note, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Gulf Power in Item 7 of the Form 10-K for additional information.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Gulf Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Gulf Power had at March 31, 2009 approximately $31.5 million of cash and cash equivalents and $140 million of unused committed lines of credit with banks. Of these credit agreements, $110 million expire in 2009, $30 million expire in 2010, and $60 million of these facilities contain provisions allowing one-year term loans executable at expiration. Subsequent to March 31, 2009, Gulf Power entered into an additional $75 million of credit agreements that expire in 2010. Gulf Power expects to renew its credit facilities, as needed, prior to expiration. See Note 6 to the financial statements of Gulf Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. These credit arrangements provide liquidity support to Gulf Power’s obligations with respect to variable rate pollution control revenue bonds and commercial paper. Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and other Southern Company subsidiaries. At March 31, 2009, Gulf Power had $50 million of short-term bank debt outstanding and no commercial paper outstanding. Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.

Credit Rating Risk

Gulf Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, emissions allowances, and energy price risk management. At March 31, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $50 million. At March 31, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $271 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants 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, any credit rating downgrade could impact Gulf Power’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

Gulf Power’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Gulf Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation, Gulf Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Gulf Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Gulf Power continues to manage a fuel-hedging program implemented per the guidelines of the Florida PSC. As such, Gulf Power has no material change in market risk exposure when compared with the December 31, 2008 reporting period.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The changes in fair value of energy-related derivative contracts for the three months ended March 31, 2009 were as follows:

	First Quarter
	2009
	Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(31.2	)
Contracts realized or settled		8.0
Current period changes(a)		(20.0	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(43.2	)

(a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

The decrease in the fair value positions of the energy-related derivative contracts for the three months ended March 31, 2009 was $12 million, substantially all of which is due to natural gas positions. This change is attributable to both the volume and prices of natural gas. At March 31, 2009, Gulf Power had a net hedge volume of 16.0 Bcf with a weighted average contract cost approximately $2.76 per mmBtu above market prices, compared to 14.2 Bcf at December 31, 2008 with a weighted average contract cost approximately $2.24 per mmBtu above market prices. Natural gas hedges are recovered through the fuel cost recovery clause.

At March 31, 2009, the fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:

	March 31, 2009
	(in millions)
Regulatory hedges	$	(43.2	)
Not designated		—
Total fair value	$	(43.2	)

Energy-related derivative contracts which are designated as regulatory hedges relate to Gulf Power’s fuel hedging program where 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 fuel cost recovery clause. 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.

Unrealized pre-tax gains and losses recognized in income for the three months ended March 31, 2009 and 2008 for energy-related derivative contracts that are not hedges were not material.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2009 are as follows:

	March 31, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(43.2	)		(35.2	)		(7.7	)		(0.3	)
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(43.2	)	$	(35.2	)	$	(7.7	)	$	(0.3	)

Gulf Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Gulf Power in Item 7 and Notes 1 and 6 to the financial statements of Gulf Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein.

Financing Activities

On January 22, 2009, Gulf Power issued to Southern Company 1,350,000 shares of Gulf Power common stock, without par value, and realized proceeds of $135 million. The proceeds were used to repay a portion of Gulf Power’s short-term debt and for other general corporate purposes.

Also during the first quarter 2009, Gulf Power incurred obligations related to the issuance of $130.4 million in pollution control revenue bonds. As of March 31, 2009, $9.9 million of these pollution control revenue bonds have been classified as current liabilities, since short-term credit facilities are being used to provide liquidity support for these bonds. The proceeds are being used for the acquisition, construction, installation, and equipping of certain solid waste disposal facilities located at Plant Crist.

In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm-recovery, Gulf Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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MISSISSIPPI POWER COMPANY

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MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009			2008
	(in thousands)
Operating Revenues:
Retail revenues	$	175,735		$	168,389
Wholesale revenues —
Non-affiliates		80,154			84,806
Affiliates		9,418			28,379
Other revenues		3,416			3,842
Total operating revenues		268,723			285,416
Operating Expenses:
Fuel		119,965			130,116
Purchased power —
Non-affiliates		2,835			2,255
Affiliates		21,805			25,998
Other operations and maintenance		59,761			64,773
Depreciation and amortization		18,015			17,997
Taxes other than income taxes		14,924			15,565
Total operating expenses		237,305			256,704
Operating Income		31,418			28,712
Other Income and (Expense):
Interest income		632			409
Interest expense, net of amounts capitalized		(4,762	)		(4,441	)
Other income (expense), net		1,629			1,619
Total other income and (expense)		(2,501	)		(2,413	)
Earnings Before Income Taxes		28,917			26,299
Income taxes		10,513			9,694
Net Income		18,404			16,605
Dividends on Preferred Stock		433			433
Net Income After Dividends on Preferred Stock	$	17,971		$	16,172

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009		2008
	(in thousands)
Net Income After Dividends on Preferred Stock	$	17,971	$	16,172
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $166 and $(1,310), respectively		268		(2,114	)
Total other comprehensive income (loss)		268		(2,114	)
COMPREHENSIVE INCOME	$	18,239	$	14,058

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	18,404		$	16,605
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization		19,479			18,556
Deferred income taxes and investment tax credits, net		(4,562	)		(4,498	)
Pension, postretirement, and other employee benefits		1,902			1,606
Stock option expense		657			458
Tax benefit of stock options		10			80
Other, net		(8,523	)		(4,878	)
Changes in certain current assets and liabilities —
Receivables		32,327			(4,768	)
Fossil fuel stock		(20,315	)		(3,852	)
Materials and supplies		(379	)		(12,769	)
Prepaid income taxes		1,061			4,305
Other current assets		(2,592	)		1,775
Other accounts payable		(17,890	)		8,247
Accrued taxes		(18,604	)		(21,608	)
Accrued compensation		(15,483	)		(15,825	)
Other current liabilities		1,629			2,109
Net cash used for operating activities		(12,879	)		(14,457	)
Investing Activities:
Property additions		(26,476	)		(25,983	)
Cost of removal, net of salvage		(2,941	)		(151	)
Construction payables		1,082			2,410
Other		(506	)		(565	)
Net cash used for investing activities		(28,841	)		(24,289	)
Financing Activities:
Increase (decrease) in notes payable, net		(26,293	)		1,850
Proceeds —
Capital contributions		1,294			1,180
Gross excess tax benefit of stock options		50			215
Senior notes		125,000			—
Other long-term debt		—			80,000
Redemptions —
Senior notes		(40,000	)		—
Payment of preferred stock dividends		(433	)		(433	)
Payment of common stock dividends		(17,125	)		(17,100	)
Other		(1,792	)		—
Net cash provided from financing activities		40,701			65,712
Net Change in Cash and Cash Equivalents		(1,019	)		26,966
Cash and Cash Equivalents at Beginning of Period		22,413			4,827
Cash and Cash Equivalents at End of Period	$	21,394		$	31,793
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $125 and $29 capitalized for 2009 and 2008, respectively)	$	3,847		$	3,847
Income taxes (net of refunds)	$	(2,325	)	$	(35	)

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At March 31,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	21,394		$	22,413
Receivables —
Customer accounts receivable		39,623			40,262
Unbilled revenues		23,558			24,798
Under recovered regulatory clause revenues		42,047			54,994
Other accounts and notes receivable		5,243			8,995
Affiliated companies		10,360			24,108
Accumulated provision for uncollectible accounts		(842	)		(1,039	)
Fossil fuel stock, at average cost		105,853			85,538
Materials and supplies, at average cost		27,523			27,143
Other regulatory assets		76,691			59,220
Other		12,782			10,898
Total current assets		364,232			357,330
Property, Plant, and Equipment:
In service		2,244,657			2,234,573
Less accumulated provision for depreciation		932,791			923,269
		1,311,866			1,311,304
Construction work in progress		80,809			70,665
Total property, plant, and equipment		1,392,675			1,381,969
Other Property and Investments		7,976			8,280
Deferred Charges and Other Assets:
Deferred charges related to income taxes		9,260			9,566
Other regulatory assets		185,461			171,680
Other		24,742			23,870
Total deferred charges and other assets		219,463			205,116
Total Assets	$	1,984,346		$	1,952,695

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)

	At March 31,		At December 31,
Liabilities and Stockholder’s Equity	2009		2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	1,254	$	41,230
Notes payable		—		26,293
Accounts payable —
Affiliated		37,175		36,847
Other		46,569		63,704
Customer deposits		10,536		10,354
Accrued taxes —
Income taxes		19,815		8,842
Other		17,148		50,700
Accrued interest		4,683		3,930
Accrued compensation		5,120		20,604
Other regulatory liabilities		8,846		9,718
Liabilities from risk management activities		47,045		29,291
Other		17,964		19,144
Total current liabilities		216,155		320,657
Long-term Debt		494,360		370,460
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		222,009		222,324
Deferred credits related to income taxes		13,854		14,074
Accumulated deferred investment tax credits		13,716		14,014
Employee benefit obligations		143,308		142,188
Other cost of removal obligations		97,243		96,191
Other regulatory liabilities		52,714		51,340
Other		58,632		52,216
Total deferred credits and other liabilities		601,476		592,347
Total Liabilities		1,311,991		1,283,464
Preferred Stock		32,780		32,780
Common Stockholder’s Equity:
Common stock, without par value —
Authorized - 1,130,000 shares
Outstanding - 1,121,000 shares		37,691		37,691
Paid-in capital		321,968		319,958
Retained earnings		279,648		278,802
Accumulated other comprehensive income (loss)		268		—
Total common stockholder’s equity		639,575		636,451
Total Liabilities and Stockholder’s Equity	$	1,984,346	$	1,952,695

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2009 vs. FIRST QUARTER 2008

OVERVIEW

Mississippi Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Mississippi and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Mississippi Power’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain energy sales in the midst of the current economic downturn, and to effectively manage and secure timely recovery of rising costs. Mississippi Power has various regulatory mechanisms that operate to address cost recovery. Appropriately balancing required costs and capital expenditures with reasonable retail rates will continue to challenge Mississippi Power for the foreseeable future.

Mississippi Power continues to focus on several key performance indicators. In recognition that Mississippi Power’s long-term financial success is dependent upon how well it satisfies its customers’ needs, Mississippi Power’s retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power’s allowed return. In addition to the PEP performance indicators, Mississippi Power focuses on other performance measures, including broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Mississippi Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$1.8	11.1

Mississippi Power’s net income after dividends on preferred stock for the first quarter 2009 was $18.0 million compared to $16.2 million for the corresponding period in 2008. The increase was primarily due to a decrease in operations and maintenance expenses, an increase related to the reclassification of 2008 System Restoration Rider (SRR) revenue reductions to expense pursuant to an order from the Mississippi PSC dated January 9, 2009, and an increase in territorial base revenues resulting from an increase in wholesale demand, partially offset by a decrease in wholesale energy revenues.

Retail Revenues

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$7.3	4.4

In the first quarter 2009, retail revenues were $175.7 million compared to $168.4 million for the same period in 2008.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the change to retail revenues are as follows:

	First Quarter
	2009
	(in millions)			(% change)
Retail – prior year	$	168.4
Estimated change in —
Rates and pricing		1.6			1.0
Sales growth (decline)		(2.2	)		(1.3	)
Weather		(1.1	)		(0.7	)
Fuel and other cost recovery		9.0			5.4
Retail – current year	$	175.7			4.4	%

Revenues associated with changes in rates and pricing increased in the first quarter 2009 when compared to the same period in 2008 due to a $1.0 million increase related to the reclassification of 2008 SRR revenue reductions to expense pursuant to an order from the Mississippi PSC dated January 9, 2009 and an increase in base rates of $0.9 million related to a rate change effective in mid-January 2008. These increases were partially offset by decreases in retail revenues of approximately $0.3 million related to the ECO Plan rate. For additional information on SRR, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – System Restoration Rider” of Mississippi Power in Item 7 of the Form 10-K.

Revenues attributable to changes in sales growth declined in the first quarter 2009 when compared to the same period in 2008 due to 3.0% and 0.9% decreases in weather-adjusted KWH sales to residential and commercial customers, respectively, and a 6.6% decrease in KWH sales to industrial customers. The decrease in weather-adjusted KWH sales to residential and commercial customers is primarily due to a recessionary economy. The decrease in industrial sales is primarily due to lower production levels experienced by industrial customers resulting from a recessionary economy.

Revenues resulting from changes in weather were minimal although weather conditions were milder for the first quarter 2009 when compared to the first quarter 2008.

Fuel and other cost recovery revenues increased in the first quarter 2009 when compared to the same period in 2008 primarily as a result of higher recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power’s service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.

Wholesale Revenues – Non-Affiliates

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(4.6)	(5.5)

Wholesale revenues from non-affiliates will vary depending on the market cost of available energy compared to the cost of Mississippi Power and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the first quarter 2009, wholesale revenues from non-affiliates were $80.2 million compared to $84.8 million for the same period in 2008. The decrease was due to decreased revenues from customers outside Mississippi Power’s service territory of $11.9 million, partially offset by $7.3 million increased revenues from customers inside Mississippi Power’s service territory. The $11.9 million decrease in revenues from customers outside Mississippi Power’s service territory was due to a $7.4 million decrease associated with lower prices resulting from lower marginal cost of fuel, a $4.2 million decrease in sales, and a $0.3 million decrease in capacity revenues. The $7.3 million increase in revenues from customers inside Mississippi Power’s service territory was due to a $3.9 million increase in recoverable fuel costs and higher demand by customers of approximately $3.4 million.

Wholesale Revenues – Affiliates

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(19.0)	(66.8)

Wholesale revenues from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost.

In the first quarter 2009, wholesale revenues from affiliates were $9.4 million compared to $28.4 million for the same period in 2008. The decrease was primarily due to a $19.2 million decrease in energy revenues, of which $18.0 million was associated with decreased sales and $1.2 million was associated with lower prices. Capacity revenues increased $0.2 million.

Fuel and Purchased Power Expenses

	First Quarter 2009
	vs.
	First Quarter 2008
	(change in millions)			(% change)
Fuel	$	(10.1	)		(7.8	)
Purchased power – non-affiliates		0.5			25.7
Purchased power – affiliates		(4.2	)		(16.1	)
Total fuel and purchased power expenses	$	(13.8	)

In the first quarter 2009, total fuel and purchased power expenses were $144.6 million compared to $158.4 million for the same period in 2008. This decrease was primarily due to an $18.7 million decrease in total KWHs generated and purchased, partially offset by a $4.9 million net increase in the cost of fuel and purchased power.

Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – “FERC and Mississippi PSC Matters – Retail Regulatory Matters” herein for additional information.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of Mississippi Power’s cost of generation and purchased power are as follows:

	First Quarter		First Quarter		Percent
Average Cost	2009		2008		Change
	(cents per net KWH)
Fuel		4.44		3.91		13.6
Purchased power		3.91		5.40		(27.6	)

In the first quarter 2009, fuel expense was $120.0 million compared to $130.1 million for the same period in 2008. The decrease was primarily due to an 18.8% decrease in generation from Mississippi Power facilities resulting from lower energy sales and purchased power available at a lower cost, partially offset by a 13.6% increase in the price of fuel primarily due to an increase in coal prices.

Non-Affiliates

In the first quarter 2009, purchased power expense from non-affiliates was $2.8 million compared to $2.3 million for the same period in 2008. The increase was primarily the result of a 77.0% increase in KWH volume purchased, partially offset by a 29.0% decrease in the average cost of purchased power per KWH. The increase in volume was a result of lower cost opportunity purchases, while the decrease in prices was due to a lower marginal cost of fuel.

Energy purchases from non-affiliates will vary depending on the market cost of available energy being lower than the cost of Southern Company system-generated energy, demand for energy within the Southern Company system service territory, and availability of Southern Company system generation.

Affiliates

In the first quarter 2009, purchased power expense from affiliates was $21.8 million compared to $26.0 million for the same period in 2008. The decrease was primarily due to a 20.7% decrease in the average cost of purchased power per KWH, partially offset by a 5.8% increase in KWH volume purchased.

Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC, as approved by the FERC.

Other Operations and Maintenance Expenses

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(4.9)	(7.7)

In the first quarter 2009, other operations and maintenance expenses were $59.8 million compared to $64.7 million for the same period in 2008. This decrease was primarily due to generation construction screening expenses of $1.7 million incurred in the first quarter 2008 which were originally expensed and subsequently reclassified in the fourth quarter 2008 to a regulatory asset upon the FERC’s acceptance of the wholesale rate filing in October 2008. Also contributing to the decrease were a $1.6 million decrease in generation related environmental expenses and a $1.5 million decrease in distribution expenses as a result of the timing of normal maintenance activities.

See Note 3 to the financial statements of Mississippi Power under “FERC Matters” in Item 8 of the Form 10-K for additional information.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Taxes Other Than Income Taxes

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(0.7)	(4.1)

In the first quarter 2009, taxes other than income taxes were $14.9 million compared to $15.6 million for the same period in 2008. The decrease was primarily due to a decrease in ad valorem taxes. The retail portion of the decrease in ad valorem taxes is recoverable under Mississippi Power’s ad valorem tax cost recovery clause and, therefore, does not affect net income.

Income Taxes

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$0.8	8.4

In the first quarter 2009, income taxes were $10.5 million compared to $9.7 million for the same period in 2008. The change of $0.8 million was primarily due to an increase in pre-tax income.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Mississippi Power’s future earnings potential. The level of Mississippi Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power’s business of selling electricity. These factors include Mississippi Power’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Mississippi Power’s service area. Recent recessionary conditions have negatively impacted sales growth and are expected to continue to have a negative impact on energy sales, particularly to industrial customers. The timing and extent of the economic recovery will impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Mississippi Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 17, 2009, the EPA released a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. The ultimate outcome of the proposed endangerment finding cannot be determined at this time and will depend on additional regulatory action and potential legal challenges. However, regulatory decisions that may follow from such a finding could have implications for both new and existing stationary sources, such as power plants. In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Mississippi Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

FERC and Mississippi PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Implementation of the energy auction in accordance with the MBR tariff order is expected to adequately mitigate going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Performance Evaluation Plan

The Mississippi Public Utilities Staff, pursuant to the Mississippi PSC’s 2004 order approving the current PEP, is reviewing the PEP to determine if any modifications should be made. On March 2, 2009, concurrent with this review, the annual PEP evaluation filing for 2009 was suspended. Mississippi Power anticipates that, as a result of this required review, changes to the PEP will be made. Annual evaluations will resume for 2010 under the current PEP or a revised PEP. Mississippi Power does not anticipate that the suspension of the PEP filing for 2009 will have a material impact on 2009 earnings. While the final outcome is not known, it is likely that any modifications made to the PEP will result in a lower performance incentive under the PEP and therefore smaller and/or less frequent rate changes in the future. See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters – Performance Evaluation Plan” in Item 8 of the Form 10-K for additional information regarding Mississippi Power’s base rates.

On March 16, 2009, Mississippi Power submitted its annual PEP lookback filing for 2008, which recommended no surcharge or refund. The ultimate outcome of this matter cannot now be determined.

Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Mississippi Power in Item 7 of the Form 10-K for information regarding Mississippi Power’s fuel cost recovery. The Mississippi PSC approved the retail fuel cost recovery factor on March 3, 2009, with the new rates effective in March 2009. The retail fuel cost recovery factor will result in an annual increase in an amount equal to 10.3% of total 2008 retail revenues based on ten months of recovery under the new rate. At March 31, 2009, the amount of under recovered retail fuel costs included in the balance sheet was $32.4 million compared to $36.0 million at December 31, 2008. Mississippi Power also has a wholesale Municipal and Rural Associations (MRA) and Market Base (MB) fuel cost recovery factor. Effective January 1, 2009, the wholesale MRA fuel rate increased resulting in an annual increase in an amount equal to 13.9% of total 2008 MRA revenues. Effective February 1, 2009, the wholesale MB fuel rate increased resulting in an annual increase in an amount equal to 16.7% of total 2008 MB revenues. At March 31, 2009, the amount of under recovered wholesale MRA and MB fuel costs included in the balance sheet was $7.0 million and $2.6 million compared to $15.4 million and $3.7 million, respectively, at December 31, 2008. Mississippi Power’s operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, this increase to the billing factor will have no significant effect on Mississippi Power’s revenues or net income, but will increase annual cash flow.

In October 2008, the Mississippi PSC opened a docket to investigate and review interest and carrying charges under the fuel adjustment clause for utilities within the State of Mississippi including Mississippi Power. A hearing was held in November 2008 to hear testimony regarding the method of calculating carrying charges on over and under recoveries of fuel-related costs. On March 4, 2009, the Mississippi PSC issued an order to apply the prime rate in calculating the carrying costs on the retail over or under recovery balances related to fuel cost recovery. The order also requires Mississippi Power to file a proposed carrying cost calculation methodology as part of its compliance filing. Mississippi Power is currently in the process of submitting the compliance filing. The ultimate outcome of this matter cannot now be determined.

92

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Integrated Coal Gasification Combined Cycle

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Integrated Coal Gasification Combined Cycle” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K for information regarding the Kemper IGCC.

On April 6, 2009, the Governor of the State of Mississippi signed into law a bill that will provide an ad valorem tax exemption for a portion of the assessed value of all property utilized in certain electric generating facilities with integrated gasification process facilities. This tax exemption, which may not exceed 50% of the total value of the project, is for projects with a capital investment from private sources of $1 billion or more.

On April 6, 2009, Mississippi Power received an accounting order from the Mississippi PSC directing Mississippi Power to continue to charge all Kemper IGCC generation resources planning, evaluation, and screening costs to regulatory assets including those costs associated with activities to obtain a certificate of public convenience and necessity and costs necessary and prudent to preserve the availability, economic viability, and/or required schedule of the selected generation resource until the Mississippi PSC makes findings and determination as to the recovery of Mississippi Power’s prudent expenditures.

As of March 31, 2009, Mississippi Power had spent a total of $50.7 million associated with Mississippi Power’s generation resource planning, evaluation, and screening activities, including regulatory filings costs. Costs incurred during the first quarter 2009 totaled $8.4 million as compared to $7.2 million during the first quarter 2008. Of the total $50.7 million, $46.2 million was deferred in other regulatory assets, $3.7 million was related to land purchases capitalized, and $0.8 million was previously expensed.

Several motions have been filed by intervenors in this proceeding, most of which are procedural in nature and seek to stay or delay the timely and orderly administration of the docket. In addition to these procedural motions, a motion has been filed by the Attorney General for the State of Mississippi which questions whether the Mississippi PSC has authority to approve the gasification portion of the Kemper IGCC. All of these motions were heard by the Mississippi PSC on May 5, 2009.

The ultimate outcome of these matters cannot now be determined.

Income Tax Matters

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Mississippi Power. Mississippi Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $11 million and $14 million. Mississippi Power is currently assessing the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Matters

Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power’s business activities are subject to extensive governmental regulation related to public health and the environment. 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 opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Mississippi Power’s financial statements.

See the Notes to the Condensed Financial Statements herein for 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

Mississippi Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Plant Daniel Operating Lease.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Mississippi Power’s financial condition remained stable at March 31, 2009. Throughout the recent turmoil in the financial markets, Mississippi Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper programs and variable rate pollution control revenue bonds. Mississippi Power has continued to issue commercial paper at reasonable rates. Mississippi Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit have increased, and Mississippi Power has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. In the first quarter 2009, Mississippi Power increased an existing facility by $10 million. Subsequent to March 31, 2009, Mississippi Power entered into an additional committed credit facility resulting in a net increase of $40 million. Total committed credit fees at Mississippi Power average less than ¹/4 of 1% per year. Mississippi Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. Mississippi Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. The ultimate impact on future financing costs as a result of the financial turmoil cannot be determined at this time. See “Sources of Capital” and “Financing Activities” herein for additional information.

94

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi Power’s investments in pension trust funds have continued to decline in value during the first quarter 2009. Mississippi Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2011 and such contribution could be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time.

Net cash used for operating activities totaled $12.9 million for the first three months of 2009, compared to $14.5 million for the corresponding period in 2008. The $1.6 million decrease in cash used for operating activities is primarily due to increases in joint ownership billings of $13.7 million and cash inflows resulting from fuel cost recovery of $12.9 million, partially offset by cash outflows in other accounts payable of $9.6 million related to fuel purchases and increases in fossil fuel stock of $15.7 million. The $4.6 million increase in net cash used for investing activities is primarily due to a $2.8 million cash outflow for cost of removal. The $25.0 million decrease in net cash provided from financing activities was primarily due to cash outflows resulting from $40 million of long-term senior notes that matured on March 9, 2009 and a $26 million decrease in borrowings from commercial paper in 2009, partially offset by an increase in the issuance of long-term debt in the first quarter 2009 of $45 million as compared to the same period in 2008.

Significant balance sheet changes for the first three months of 2009 include a decrease in under recovered regulatory clause revenues of $12.9 million primarily due to lower fuel costs and the implementation of a higher fuel cost recovery factor in 2009. Receivables from affiliated companies decreased by $13.7 million primarily due to a decrease in joint owner billings related to Plants Daniel and Greene County. Fossil fuel inventory increased $20.3 million primarily due to increases in coal inventory and emissions allowances of $15.7 million and $6.0 million, respectively. Other regulatory assets increased $31.2 million primarily due to mark-to-market losses on forward gas contracts. Securities due within one year decreased by $40.0 million due to senior notes maturing during the first quarter 2009. Notes payable decreased by $26.3 million primarily due to a decrease in commercial paper borrowings. Accrued taxes, other decreased by $33.6 million primarily due to property tax payments of $39.8 million in the first quarter 2009. Long-term debt increased by $124 million primarily due to the issuance of senior notes in the first quarter 2009.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power’s capital requirements for its construction program, lease obligations, purchase commitments, derivative obligations, preferred stock dividends, and trust funding requirements. Approximately $1.3 million will be required through March 31, 2010 for maturities of long-term debt. 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; revised load growth estimates; storm impacts; changes in environmental statutes and regulations; changes in FERC rules and regulations; Mississippi PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; 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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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Sources of Capital

Mississippi Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Mississippi Power has primarily utilized funds from operating cash flows, short-term borrowings, external security offerings, and capital contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Mississippi Power in Item 7 of the Form 10-K for additional information.

Mississippi Power’s current liabilities sometimes exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Mississippi Power had at March 31, 2009 approximately $21.4 million of cash and cash equivalents and $108.5 million of unused committed credit arrangements with banks. All expire in 2009; however, approximately $53.5 million of these credit arrangements contain provisions allowing two-year term loans executable at expiration and $15 million contain provisions allowing one-year term loans executable at expiration. Mississippi Power expects to renew its credit facilities, as needed, prior to expiration. Subsequent to March 31, 2009, Mississippi Power entered into an additional committed credit facility resulting in a net increase of $40 million. The new credit facility expires in 2010. See Note 6 to the financial statements of Mississippi Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. These credit arrangements provide liquidity support to Mississippi Power’s commercial paper program and $40 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Mississippi Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and other Southern Company subsidiaries. At March 31, 2009, Mississippi Power had no commercial paper outstanding. Management believes that the need for working capital can be adequately met by utilizing commercial paper, lines of credit, and cash.

Off-Balance Sheet Financing Arrangements

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Off-Balance Sheet Financing Arrangements” of Mississippi Power in Item 7 and Note 7 to the financial statements of Mississippi Power under “Operating Leases” in Item 8 of the Form 10-K for information related to Mississippi Power’s lease of a combined cycle generating facility at Plant Daniel.

Credit Rating Risk

Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At March 31, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $9 million. At March 31, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $231 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants 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, any credit rating downgrade could impact Mississippi Power’s ability to access capital markets, particularly the short-term debt market.

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

Market Price Risk

Mississippi Power’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Mississippi Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation, Mississippi Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Mississippi Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Mississippi Power continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. As such, Mississippi Power has no material change in market risk exposure when compared with the December 31, 2008 reporting period.

The changes in fair value of energy-related derivative contracts for the three months ended March 31, 2009 were as follows:

	First Quarter
	2009
	Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(52.0	)
Contracts realized or settled		9.0
Current period changes(a)		(33.0	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(76.0	)

(a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

The decrease in the fair value positions of the energy-related derivative contracts for the three months ended March 31, 2009 was $24 million, substantially all of which is due to natural gas positions. This change is attributable to both the volume and prices of natural gas. At March 31, 2009, Mississippi Power had a net hedge volume of 30.3 Bcf with a weighted average contract cost approximately $2.60 per mmBtu above market prices, compared to 28.9 Bcf at December 31, 2008 with a weighted average contract cost approximately $1.89 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the energy cost management clause.

At March 31, 2009, the fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:

	March 31, 2009
	(in millions)
Regulatory hedges	$	(76.4	)
Cash flow hedges		0.4
Not designated		—
Total fair value	$	(76.0	)

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

Energy-related derivative contracts which are designated as regulatory hedges relate to Mississippi Power’s fuel hedging program where 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 management clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in other comprehensive income 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.

Unrealized pre-tax gains and losses recognized in income for the three months ended March 31, 2009 and 2008 for energy-related derivative contracts that are not hedges were not material.

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2009 are as follows:

	March 31, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(76.0	)		(45.2	)		(26.1	)		(4.7	)
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(76.0	)	$	(45.2	)	$	(26.1	)	$	(4.7	)

Mississippi Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Mississippi Power in Item 7 and Notes 1 and 6 to the financial statements of Mississippi Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein.

Financing Activities

During the first quarter 2009, Mississippi Power issued $125 million of Series 2009A 5.55% Senior Notes due March 1, 2019. The proceeds were used to repay at maturity Mississippi Power’s $40 million aggregate principal amount of Series F Floating Rate Senior Notes due March 9, 2009, to repay a portion of short-term indebtedness, and for general corporate purposes including Mississippi Power’s continuous construction program.

In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm restoration costs, Mississippi Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009			2008
	(in thousands)
Operating Revenues:
Wholesale revenues —
Non-affiliates		94,612			80,469
Affiliates		135,284			133,493
Other revenues		1,621			1,570
Total operating revenues		231,517			215,532
Operating Expenses:
Fuel		65,781			36,047
Purchased power —
Non-affiliates		21,482			16,556
Affiliates		15,202			50,708
Other operations and maintenance		32,973			35,031
Depreciation and amortization		24,339			19,987
Taxes other than income taxes		4,759			4,542
Total operating expenses		164,536			162,871
Operating Income		66,981			52,661
Other Income and (Expense):
Interest expense, net of amounts capitalized		(21,559	)		(19,357	)
Other income (expense), net		(211	)		12,580
Total other income and (expense)		(21,770	)		(6,777	)
Earnings Before Income Taxes		45,211			45,884
Income taxes		17,295			16,909
Net Income	$	27,916		$	28,975

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009		2008
	(in thousands)
Net Income	$	27,916	$	28,975
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $302 and $(2,944), respectively		466		(4,561	)
Reclassification adjustment for amounts included in net income, net of tax of $935 and $1,342, respectively		1,440		2,073
Total other comprehensive income (loss)		1,906		(2,488	)
COMPREHENSIVE INCOME	$	29,822	$	26,487

The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months
	Ended March 31,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	27,916		$	28,975
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization		27,371			24,016
Deferred income taxes		18,763			11,067
Deferred revenues		(22,020	)		(26,767	)
Mark-to-market adjustments		883			14,406
Accumulated billings on construction contract		11,520			18,737
Accumulated costs on construction contract		(20,145	)		(18,630	)
Gain on sale of property		—			(6,029	)
Other, net		(134	)		1,660
Changes in certain current assets and liabilities —
Receivables		2,439			(2,355	)
Fossil fuel stock		1,464			(2,375	)
Materials and supplies		(497	)		(155	)
Prepaid income taxes		7,870			—
Other current assets		652			(214	)
Accounts payable		(19,840	)		(5,718	)
Accrued taxes		3,628			8,356
Accrued interest		(12,194	)		(12,210	)
Other current liabilities		88			(2,881	)
Net cash provided from operating activities		27,764			29,883
Investing Activities:
Property additions		(4,632	)		(24,332	)
Sale of property		—			4,999
Change in construction payables, net		(271	)		4,854
Payments pursuant to long-term service agreements		(6,136	)		(5,671	)
Other		—			(726	)
Net cash used for investing activities		(11,039	)		(20,876	)
Financing Activities:
Increase in notes payable, net		—			13,720
Proceeds — Capital contributions		1,060			897
Payment of common stock dividends		(26,525	)		(23,625	)
Net cash used for financing activities		(25,465	)		(9,008	)
Net Change in Cash and Cash Equivalents		(8,740	)		(1	)
Cash and Cash Equivalents at Beginning of Period		37,894			5
Cash and Cash Equivalents at End of Period	$	29,154		$	4
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $78 and $4,142 capitalized for 2009 and 2008, respectively)	$	30,791		$	27,717
Income taxes (net of refunds)	$	(10,003	)	$	495

The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	At March 31,		At December 31,
Assets	2009		2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	29,154	$	37,894
Receivables —
Customer accounts receivable		25,777		23,640
Other accounts receivable		1,795		2,162
Affiliated companies		31,651		33,401
Fossil fuel stock, at average cost		16,337		17,801
Materials and supplies, at average cost		27,024		26,527
Prepaid service agreements — current		18,423		26,304
Prepaid income taxes		13,602		18,066
Other prepaid expenses		2,109		2,756
Assets from risk management activities		15,563		10,799
Other		4,532		4,532
Total current assets		185,967		203,882
Property, Plant, and Equipment:
In service		2,865,524		2,847,757
Less accumulated provision for depreciation		376,361		351,193
		2,489,163		2,496,564
Construction work in progress		11,117		8,775
Total property, plant, and equipment		2,500,280		2,505,339
Deferred Charges and Other Assets:
Prepaid long-term service agreements		78,525		81,542
Other—
Affiliated		3,756		3,827
Other		18,354		18,550
Total deferred charges and other assets		100,635		103,919
Total Assets	$	2,786,882	$	2,813,140

The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	At March 31,			At December 31,
Liabilities and Stockholder’s Equity	2009			2008
	(in thousands)
Current Liabilities:
Accounts payable —
Affiliated	$	43,185		$	62,732
Other		9,767			11,278
Accrued taxes —
Income taxes		3,394			88
Other		5,910			2,343
Accrued interest		17,722			29,916
Liabilities from risk management activities		12,394			7,452
Billings in excess of cost on construction contract		3,283			11,907
Other		310			224
Total current liabilities		95,965			125,940
Long-term Debt		1,297,416			1,297,353
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		229,973			209,960
Deferred capacity revenues — Affiliated		12,884			32,211
Other—
Affiliated		6,408			6,667
Other		1,518			2,648
Total deferred credits and other liabilities		250,783			251,486
Total Liabilities		1,644,164			1,674,779
Common Stockholder’s Equity:
Common stock, par value $.01 per share —
Authorized - 1,000,000 shares
Outstanding - 1,000 shares		—			—
Paid-in capital		863,169			862,109
Retained earnings		303,700			302,309
Accumulated other comprehensive loss		(24,151	)		(26,057	)
Total common stockholder’s equity		1,142,718			1,138,361
Total Liabilities and Stockholder’s Equity	$	2,786,882		$	2,813,140

The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

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

FIRST QUARTER 2009 vs. FIRST QUARTER 2008

OVERVIEW

Southern Power and its wholly-owned subsidiaries construct, acquire, own, and manage generation assets and sell electricity at market-based prices in the southeastern wholesale market. Southern Power continues to execute its regional strategy through a combination of acquiring and constructing new power plants and by entering into PPAs with investor owned utilities, independent power producers, municipalities, and electric cooperatives.

To evaluate operating results and to ensure Southern Power’s ability to meet its contractual commitments to customers, Southern Power focuses on several key performance indicators. These indicators include peak season equivalent forced outage rate (EFOR), return on invested capital (ROIC), and net income. EFOR defines the hours during peak demand times when Southern Power’s generating units are not available due to forced outages (the lower the better). ROIC is focused on earning a return on all invested capital that meets or exceeds Southern Power’s weighted average cost of capital. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Southern Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(1.1)	(3.7)

Southern Power’s net income for the first quarter 2009 was $27.9 million compared to $29.0 million for the corresponding period in 2008. The decrease was primarily due to a gain on the sale of an undeveloped tract of land in Orange County, Florida to the Orlando Utilities Commission (OUC) and the receipt of a fee for participating in an asset auction that were both recognized in income in the first quarter 2008. The decrease was also due to increased depreciation associated with Plant Franklin Unit 3 being placed into commercial operation in June 2008 and increased depreciation associated with an increase in depreciation rates. These unfavorable impacts were partially offset by increased revenues associated with Plant Franklin Unit 3 being placed into commercial operation in June 2008 and increased generation from Southern Power’s combined cycle units due to lower natural gas prices.

Wholesale Revenues – Affiliates and Wholesale Revenues – Non-Affiliates

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$15.9	7.4

Wholesale revenues for the first quarter 2009 were $229.9 million compared to $214.0 million for the corresponding period in 2008. Wholesale energy sales to non-affiliates will vary depending on the energy demand of those customers and their generation capacity, as well as the market cost of available

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

energy compared to the cost of Southern Power’s energy. Energy sales to affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company. Sales to affiliate companies that are not covered by PPAs are made in accordance with the IIC, as approved by the FERC. Wholesale revenues from non-affiliates increased $14.1 million during the period, primarily due to revenues from Plant Franklin Unit 3 of $8.6 million and mark-to-market gains on sales of uncontracted generating capacity of $4.5 million in the first quarter 2009. Southern Power recognized $28.3 million in mark-to-market losses in the first quarter 2008. Decreases in revenues of $27.3 million due to lower natural gas prices and reduced sales of uncontracted generating capacity partially offset these increases in the first quarter 2009. Wholesale revenues from affiliates increased $1.8 million during the period, primarily due to increased energy revenues from non-PPA power sales under the IIC.

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Power Sales Agreements” of Southern Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – “Power Sales Agreements” herein for additional information.

Fuel and Purchased Power Expenses

	First Quarter 2009 vs. First Quarter 2008
	(change in millions)			(% change)
Fuel	$	29.7			82.5
Purchased power – non-affiliates		4.9			29.8
Purchased power – affiliates		(35.5	)		(70.0	)
Total fuel and purchased power expenses	$	(0.8	)

In the first quarter 2009, total fuel and purchased power expenses were $102.5 million compared to $103.3 million for the corresponding period in 2008. Fuel expense increased $67.0 million due to a 40.7% increase in generation associated with Plant Franklin Unit 3 being placed into commercial operation in June 2008 and increased generation at Southern Power’s other combined cycle units due to lower natural gas prices. Additionally, $11.9 million in mark-to-market gains were recognized in the first quarter 2008 versus $3.9 million in mark-to-market losses recognized in the first quarter 2009. These increases were offset by a $51.4 million reduction in fuel expense due to a 24.7% decrease in the average cost of natural gas. Purchased power decreased $30.6 million due to increased generation at Southern Power’s combined cycle units during the first quarter 2009 due to the lower natural gas prices.

Other Operations and Maintenance Expenses

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(2.1)	(5.9)

In the first quarter 2009, other operations and maintenance expenses were $33.0 million compared to $35.0 million for the same period in 2008. The decrease was primarily due to transmission tariff penalties of $3.6 million recognized in 2008, partially offset by an increase in plant maintenance activities of $1.5 million.

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

Depreciation and Amortization

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$4.3	21.8

In the first quarter 2009, depreciation and amortization was $24.3 million compared to $20.0 million for the corresponding period in 2008. The increase was primarily due to completion of Plant Franklin Unit 3 in June 2008 and higher depreciation rates implemented in January 2009. See Note 1 to the financial statements of Southern Power under “Depreciation” in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under “Southern Power Depreciation Policy” herein for additional information.

Interest Expense, Net of Amounts Capitalized

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$2.2	11.4

In the first quarter 2009, interest expense, net of amounts capitalized was $21.6 million compared to $19.4 million for the corresponding period in 2008. The increase was primarily the result of a decrease in capitalized interest as a result of the completion of Plant Franklin Unit 3 in June 2008, partially offset by a decrease in short-term borrowing levels in the first quarter 2009.

Other Income (Expense), Net

First Quarter 2009 vs. First Quarter 2008
(change in millions)	(% change)
$(12.8)	(101.7)

In the first quarter 2009, other income (expense), net was $(0.2) million compared to $12.6 million for the corresponding period in 2008. The change was primarily due to a $6.0 million gain on the sale of an undeveloped tract of land in Orange County, Florida to the OUC and a $6.4 million fee received for participating in an asset auction that were both recognized in the first quarter 2008. Southern Power was not a successful bidder in the auction.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power’s future earnings potential. The level of Southern Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power’s competitive wholesale business. These factors include Southern Power’s ability to achieve sales growth while containing costs. Another major factor is federal regulatory policy, which may impact Southern Power’s level of participation in the market. The level of future earnings also depends on numerous factors including regulatory matters (such as those related to affiliate contracts), creditworthiness of customers, total generating capacity

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

available in the Southeast, the successful remarketing of capacity as current contracts expire, and Southern Power’s ability to execute its acquisition strategy. Recent recessionary conditions have negatively impacted capacity revenues. The timing and extent of the economic recovery will impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

Environmental Matters

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also affect earnings. While Southern Power’s PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time.

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Southern Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 17, 2009, the EPA released a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. The ultimate outcome of the proposed endangerment finding cannot be determined at this time and will depend on additional regulatory action and potential legal challenges. However, regulatory decisions that may follow from such a finding could have implications for both new and existing stationary sources, such as power plants. In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Southern Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future results of operations, cash flows, and financial condition.

FERC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff.

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

The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. Implementation of the energy auction in accordance with the MBR tariff order is expected to adequately mitigate going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

Income Tax Matters

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives. Southern Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be immaterial. Southern Power is currently assessing the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Construction Projects

Cleveland County Units 1-4

In December 2008, Southern Power announced that it will build an electric generating plant in Cleveland County, North Carolina. The plant will consist of four combustion turbine natural gas generating units with a total generating capacity of 720 MW. The units are expected to go into commercial operation in 2012. Costs incurred through March 31, 2009 were $7.1 million. The total estimated construction cost is expected to be between $350 million and $400 million.

Power Sales Agreements

Southern Power has entered into PPAs with North Carolina Electric Membership Corporation (NCEMC) and North Carolina Municipal Power Agency No. 1 (NCMPA1) for a portion of the generating capacity from the Cleveland County plant that will begin in 2012 and expire in 2036 and 2031, respectively. NCEMC will purchase 180 MW of capacity that will be supported by one unit at the plant and will purchase capacity from a second unit at the plant that will increase to 180 MW over a seven-year phase-in period. NCMPA1 will purchase 180 MW from a third unit at the plant.

The NCEMC PPAs were approved by Rural Utilities Service on March 6, 2009.

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

Potential Acquisition

On April 2, 2009, Southern Power signed an agreement to acquire all of the outstanding general and limited partnership interests of Hartwell Energy Limited Partnership (Hartwell). Hartwell owns a dual fueled generating plant near Hartwell, Georgia with installed capacity of 318 MWs. The plant consists of two combustion turbine natural gas generating units with oil back-up. The entire output of the plant is sold under a PPA with Oglethorpe Power Corporation (Oglethorpe) through May 31, 2019.

The acquisition is subject to a right of first refusal held by Oglethorpe, certain regulatory approvals, and other conditions. Oglethorpe’s right of first refusal expires July 31, 2009. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power’s business activities are subject to extensive governmental regulation related to public health and the environment. 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 opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such potential litigation against Southern Power and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Southern Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from any such proceedings would have a material adverse effect on Southern Power’s financial statements.

See Note (B) to the Condensed Financial Statements herein for 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

Southern Power prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS– ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power’s critical accounting policies and estimates related to Revenue Recognition, Normal Sale and Non-Derivative Transactions, Cash Flow Hedge Transactions, Mark-to-Market Transactions, Percentage of Completion, Asset Impairments, Acquisition Accounting, Contingent Obligations, and Depreciation.

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power’s financial condition remained stable at March 31, 2009. Throughout the recent turmoil in the financial markets, Southern Power has maintained cash balances to cover the majority of its capital needs and has had limited need to issue commercial paper or draw on committed credit arrangements. During the first quarter 2009, Southern Power successfully accessed the commercial paper market when needed. There was no commercial paper outstanding at March 31, 2009. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements as needed to meet future capital and liquidity needs. Market rates for committed credit have increased, and Southern Power may be subject to higher costs as its existing facilities are replaced or renewed. The current facility expires in 2012 and the commitment fee is less than ¹/₈ of 1%. Southern Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. The ultimate impact on future financing costs as a result of the financial turmoil cannot be determined at this time. See “Sources of Capital” herein for additional information on lines of credit.

Net cash provided from operating activities totaled $27.8 million for the first three months of 2009, compared to $29.9 million for the corresponding period in 2008. The $2.1 million decrease in cash provided from operating activities was primarily due to cash outflows for engineering, procurement, and construction services to build a combined cycle unit for the OUC. The OUC contract is not expected to have any positive or negative impacts to Southern Power over the term of the contract as Southern Power is not anticipating any profit or loss from this transaction at this time. Additionally, a fee for participating in an asset auction was received in the first quarter 2008. These decreases were partially offset by the receipt of an income tax refund in 2009 and collection of accounts receivable balances from 2008. Net cash used for investing activities totaled $11.0 million for the first three months of 2009, compared to $20.9 million for the corresponding period in 2008. The $9.9 million decrease is primarily due to reduced property additions as Plant Franklin Unit 3 was completed in June 2008. Net cash used in financing activities totaled $25.5 million for the first three months of 2009 compared to $9.0 million for the corresponding period in 2008. The increase was primarily due to a reduction in short-term borrowing in 2009 and an increase in dividends paid to Southern Company.

Significant asset changes in the balance sheet for the first three months of 2009 include a reduction in affiliate accounts receivable due to reduced energy sales under the IIC, a reduction in prepaid long-term service agreements due to completion of scheduled outages.

Significant liability and stockholder’s equity changes in the balance sheet for the first three months of 2009 include a reduction in affiliate accounts payable due to timing of payments to SCS, a reduction in accrued interest due to interest payments, a reduction in billings in excess of cost due to increased spending on the OUC construction contract, and a reduction in deferred capacity revenues due to levelization.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Southern Power in Item 7 of the Form 10-K for a description of Southern Power’s capital requirements for its construction program,

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

maturing debt, interest, leases, derivative obligations, purchase commitments, and long-term service agreements. The construction programs are subject to periodic review and revision; these amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements. Planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power’s ability to execute its growth strategy. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital.

Sources of Capital

Southern Power may use operating cash flows, external funds, equity capital, or loans from Southern Company to finance any new projects, acquisitions, and ongoing capital requirements. Southern Power expects to generate external funds from the issuance of unsecured senior debt and commercial paper or utilization of credit arrangements from banks. However, the amount, type, and timing of any financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Southern Power in Item 7 of the Form 10-K for additional information.

Southern Power’s current liabilities frequently exceed current assets due to the use of short-term indebtedness as a funding source, as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet liquidity and capital resource requirements, Southern Power had at March 31, 2009 $400 million in committed credit arrangements with banks that will expire in 2012. Proceeds from these credit arrangements may be used for working capital and general corporate purposes as well as liquidity support for Southern Power’s commercial paper program. See Note 6 to the financial statements of Southern Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information.

Southern Power’s commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes.

Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Credit Rating Risk

Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, and energy price risk management. At March 31, 2009, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $338 million. At March 31, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $798 million. Included in these amounts are certain agreements that

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

could require collateral in the event that one or more Power Pool participants 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, any credit rating downgrade could impact Southern Power’s ability to access capital markets, particularly the short-term debt market.

In addition, through the acquisition of Plant Rowan, Southern Power assumed a PPA with Duke Energy that could require collateral, but not accelerated payment, in the event of a downgrade to Southern Power’s credit rating to below BBB- or Baa3. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade.

Market Price Risk

Southern Power is exposed to market risks, including changes in interest rates and certain energy-related commodity prices. To manage the volatility attributable to these exposures, Southern Power takes advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Power’s policies in areas such as counterparty exposure and hedging practices. It is Southern Power’s policy that derivatives be used primarily for hedging purposes. Derivative positions are monitored using techniques that include market valuation and sensitivity analysis.

Southern Power’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Southern Power is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Because energy from Southern Power’s facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.

The changes in fair value of energy-related derivative contracts for the three months ended March 31, 2009 were as follows:

	First Quarter
	2009
	Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	3.4
Contracts realized or settled		0.1
Current period changes(a)		(0.2	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	3.3

(a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The decrease in the fair value positions of the energy-related derivative contracts for the three months ended March 31, 2009 was $0.1 million, which is due to both power and natural gas positions. This change is attributable to both the volume and prices of power and natural gas as follows:

	March 31, 2009
Power (net sold)
MWHs (in millions)		0.7
Weighted average contract cost per MWH above (below) market prices (in dollars)	$	3.71
Natural gas (net purchase)
Commodity – Bcf		3.5
Location basis – Bcf		2.0
Commodity – Weighted average contract cost per mmBtu above (below) market prices (in dollars)	$	(0.27	)
Location basis – Weighted average contract cost per mmBtu above (below) market prices (in dollars)	$	0.06

At March 31, 2009, the fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:

	March 31, 2009
	(in millions)
Cash flow hedges	$	—
Not designated		3.3
Total fair value	$	3.3

Gains and losses on energy-related derivatives used by Southern Power to hedge anticipated purchases and sales are initially deferred in other comprehensive income before being recognized in income in the same period as the hedged transaction. Gains and losses on derivative contracts that are not designated as hedges are recognized in the statements of income as incurred.

Total net unrealized pre-tax losses recognized in the statements of income for the three months ended March 31, 2009 for energy-related derivative contracts that are not hedges was $1 million and will continue to be marked to market until the settlement date. For the three months ended March 31, 2008, the total net unrealized losses recognized in the statements of income were $14 million. See Note (F) to the Condensed Financial Statements herein for further details of these losses.

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2009 are as follows:

	March 31, 2009
	Fair Value Measurements
	Total		Maturity
	Fair Value		Year 1		Years 2&3		Years 4&5
	(in millions)
Level 1	$	—	$	—	$	—	$	—
Level 2		3.3		3.2		0.1		—
Level 3		—		—		—		—
Fair value of contracts outstanding at end of period	$	3.3	$	3.2	$	0.1	$	—

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

Southern Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Southern Power in Item 7 and Notes 1 and 6 to the financial statements of Southern Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein.

Financing Activities

Southern Power did not issue or redeem any long-term securities during the three months ended March 31, 2009.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

INDEX TO APPLICABLE NOTES TO
FINANCIAL STATEMENTS BY REGISTRANT

Registrant	Applicable Notes
Southern Company	A, B, C, D, E, F, G, H, I
Alabama Power	A, B, C, F, G, H
Georgia Power	A, B, C, D, F, G, H
Gulf Power	A, B, C, F, G, H
Mississippi Power	A, B, C, D, F, G, H
Southern Power	A, B, C, F, H

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:

(A)	INTRODUCTION
	The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2008 have been derived from the audited financial statements of each registrant. In the opinion of each registrant’s management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended March 31, 2009 and 2008. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented do not necessarily indicate operating results for the entire year.
	Reclassifications
	Certain prior period data presented in the financial statements have been reclassified to conform to the current year presentation.
	For comparative purposes, each registrant’s statement of income for the three months ended March 31, 2008 was modified within the operating expenses section to combine the line items “Other operations” and “Maintenance” into a single line item entitled “Other operations and maintenance.” The balance sheets at December 31, 2008 of Southern Company, Alabama Power, and Georgia Power were modified to present a separate line item for “Other regulatory assets” previously included in “Other.” In addition, Georgia Power’s balance sheet was modified to reflect a new line item “Liabilities from risk management activities” previously included in “Other.” Within the operating activities of Georgia Power’s statements of cash flows, “Deferred revenues” and “Deferred expenses” previously included in “Other, net” in the prior period are now shown as separate line items. Also, within the financing activities of the same statement, the line item “Capital leases” was collapsed into “Other.” Mississippi Power’s balance sheet was modified to combine the line item “Prepaid income taxes” with “Other current assets.” Southern Power’s consolidated statement of cash flows for the three months ended March 31, 2008 was modified within the investing activities to present separately the amount of “Payments pursuant to long-term service agreements” previously included in “Property additions.”
	These reclassifications had no effect on total assets, net income, cash flows, or earnings per share.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

	Effective January 1, 2009, Southern Company and its subsidiaries adopted retrospectively FASB Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements,” which is an amendment of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” (SFAS No. 160). In connection with the adoption of SFAS No. 160, Southern Company evaluated the requirements of Emerging Issues Task Force Topic No. 98, “Classification and Measurement of Redeemable Securities” (Topic D-98) with respect to the presentation of preferred and preference stock of subsidiaries. Based on the guidance in Topic D-98 and SFAS No. 160, the preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power are required to be shown as “noncontrolling interests,” separately presented as a component of “Stockholders’ Equity” on Southern Company’s consolidated balance sheets. 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 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 as defined in Topic D-98. The preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power do not contain such a provision that would allow the holders to elect a majority of such subsidiary’s board.
	In addition, SFAS No. 160 requires that preferred and preference dividends of subsidiaries previously presented within Southern Company’s consolidated statements of income as a component of “Other Income and (Expense)” be presented as a deduction from “Consolidated Net Income” to arrive at “Consolidated Net Income After Dividends on Preferred and Preference Stock.” In Southern Company’s consolidated statements of cash flows, the preferred and preference dividends previously classified in operating activities are now classified in financing activities.
	Southern Power Depreciation Policy
	See Note 1 to the financial statements of Southern Power under “Depreciation” in Item 8 of the Form 10-K for information regarding Southern Power’s depreciation policy. Southern Power revised its depreciation rates in 2009. The change in estimate is due to revised useful life assumptions for certain components of plant in service. The expected total impact on Southern Power’s income from continuing operations and net income for 2009 is a decrease of approximately $8.0 million and $5.0 million, respectively.
(B)	CONTINGENCIES AND REGULATORY MATTERS
	See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
	General Litigation Matters
	Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, each registrant’s business activities are subject to extensive governmental regulation related to public health and the environment. 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 opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the registrants and any of their subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on such registrant’s financial statements.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Mirant Matters

Mirant was an energy company with businesses that included independent power projects and energy trading and risk management companies in the United States and selected other countries. It was a wholly-owned subsidiary of Southern Company until its initial public offering in October 2000. In April 2001, Southern Company completed a spin-off to its shareholders of its remaining ownership, and Mirant became an independent corporate entity.

Mirant Bankruptcy

In July 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas. The Bankruptcy Court entered an order confirming Mirant’s plan of reorganization in December 2005, and Mirant announced that this plan became effective in January 2006. As part of the plan, Mirant transferred substantially all of its assets and its restructured debt to a new corporation that adopted the name Mirant Corporation (Reorganized Mirant).

Southern Company has certain contingent liabilities associated with guarantees of contractual commitments made by Mirant’s subsidiaries discussed under “Guarantees” in Note 7 to the financial statements of Southern Company in Item 8 of the Form 10-K and with various lawsuits related to Mirant discussed below. Also, Southern Company has joint and several liability with Mirant regarding the joint consolidated federal income tax returns through 2001, as discussed in Note 5 to the financial statements of Southern Company in Item 8 of the Form 10-K. In December 2004, as a result of concluding an IRS audit for the tax years 2000 and 2001, Southern Company paid approximately $39 million in additional tax and interest related to Mirant tax items and filed a claim in Mirant’s bankruptcy case for that amount. To date, Southern Company has received from the IRS approximately $38 million in refunds related to Mirant. Southern Company believes it has a right to recoup the $39 million tax payment owed by Mirant from such tax refunds. As a result, Southern Company intends to retain the tax refunds and reduce its claim against Mirant for the payment of Mirant taxes by the amount of such refunds. MC Asset Recovery, LLC, a special purpose subsidiary of Reorganized Mirant (MC Asset Recovery), has objected to and sought to equitably subordinate the Southern Company tax claim in its fraudulent transfer litigation against Southern Company. Southern Company’s proofs of claim filed in the Mirant bankruptcy survive the settlement of the MC Asset Recovery litigation. Southern Company has reserved the remaining amount with respect to its Mirant tax claim.

Under the terms of the separation agreements entered into in connection with the spin-off, Mirant agreed to indemnify Southern Company for costs associated with these guarantees, lawsuits, and additional IRS assessments. As a result of Mirant’s bankruptcy, Southern Company sought reimbursement as an unsecured creditor in Mirant’s Chapter 11 proceeding. As part of a complaint filed against Southern Company in June 2005 and amended thereafter, Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation (Unsecured Creditors’ Committee) objected to and sought equitable subordination of Southern Company’s claims, and Mirant moved to reject the separation agreements entered into in connection with the spin-off as discussed in the preceding paragraph. MC Asset Recovery has been substituted as plaintiff in the complaint. If Southern Company’s claims for indemnification with respect to these, or any additional future payments, are allowed, then Mirant’s indemnity obligations to Southern Company would constitute unsecured claims against Mirant entitled to stock in Reorganized Mirant. The final outcome of this matter cannot now be determined.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

MC Asset Recovery Litigation

In June 2005, Mirant, as a debtor in possession, and the Unsecured Creditors’ Committee filed a complaint against Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005, February 2006, May 2006, and March 2007.

In December 2005, the Bankruptcy Court entered an order authorizing the transfer of this proceeding, along with certain other actions, to MC Asset Recovery. Under that order, Reorganized Mirant was obligated to fund up to $20 million in professional fees in connection with the lawsuits, as well as certain additional amounts. Any net recoveries from these lawsuits would be distributed to, and shared equally by, certain unsecured creditors and the original equity holders. In January 2006, the U.S. District Court for the Northern District of Texas substituted MC Asset Recovery as plaintiff.

The complaint, as amended in March 2007, alleged that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company prior to the spin-off. The alleged fraudulent transfers and illegal dividends included without limitation: (1) certain dividends from Mirant to Southern Company in the aggregate amount of $668 million, (2) the repayment of certain intercompany loans and accrued interest in an aggregate amount of $1.035 billion, and (3) the dividend distribution of one share of Series B Preferred Stock and its subsequent redemption in exchange for Mirant’s 80% interest in a holding company that owned SE Finance Capital Corporation and Southern Company Capital Funding, Inc., which transfer plaintiff asserted was valued at over $200 million. The complaint also sought to recharacterize certain advances from Southern Company to Mirant for investments in energy facilities from debt to equity. The complaint further alleged that Southern Company was liable to Mirant’s creditors for the full amount of Mirant’s liability under an alter ego theory of recovery and that Southern Company breached its fiduciary duties to Mirant and its creditors, caused Mirant to breach its fiduciary duties to creditors, and aided and abetted breaches of fiduciary duties by Mirant’s directors and officers. The complaint also sought recoveries under the theories of restitution and unjust enrichment. In addition, the complaint alleged a claim under the Federal Debt Collection Procedure Act (FDCPA) to avoid certain transfers from Mirant to Southern Company; however, in July 2008, the court ruled that the FDCPA does not apply and that Georgia law should apply instead. The complaint sought monetary damages in excess of $2 billion plus interest, punitive damages, attorneys’ fees, and costs. Finally, the complaint included an objection to Southern Company’s pending claims against Mirant in the Bankruptcy Court (which relate to reimbursement under the separation agreements of payments such as income taxes, interest, legal fees, and other guarantees described in Note 7 to the financial statements of Southern Company in Item 8 of the Form 10-K) and sought equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company served an answer to the complaint in April 2007.

In January 2006, the U.S. District Court for the Northern District of Texas granted Southern Company’s motion to withdraw this action from the Bankruptcy Court and, in February 2006, granted Southern Company’s motion to transfer the case to the U.S. District Court for the Northern District of Georgia. In May 2006, Southern Company filed a motion for summary judgment seeking entry of judgment against the plaintiff as to all counts of the complaint. In December 2006, the U.S. District Court for the Northern District of Georgia granted in part and denied in part the motion. As a result, certain breach of fiduciary duty claims alleged in earlier versions of the complaint were barred; all other claims in the complaint were allowed to proceed. In August 2008, Southern Company filed a second motion for summary judgment. MC Asset Recovery filed its response to Southern Company’s motion for summary judgment in October 2008. On February 5, 2009, the court denied the summary judgment motion in connection with the fraudulent conveyance and illegal dividend claims concerning certain advance return/loan repayments in 1999, dividends in 1999 and 2000, and

119

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

transfers in connection with Mirant’s separation from Southern Company. The court granted Southern Company’s motion for summary judgment with respect to certain claims, including claims for restitution and unjust enrichment, claims that Southern Company aided and abetted Mirant’s directors’ breach of fiduciary duties to Mirant, and claims that Southern Company used Mirant as an alter ego. In addition, the court granted Southern Company’s motion in connection with the fraudulent transfer and illegal dividend claims concerning certain turbine termination payments.

On March 31, 2009, Southern Company entered into a settlement agreement with MC Asset Recovery to resolve the action. The settlement includes an agreement by Southern Company to pay MC Asset Recovery $202 million and requires MC Asset Recovery to release Southern Company and certain other designated avoidance actions assigned to MC Asset Recovery in connection with Mirant’s plan of reorganization, as well as to release all actions against current or former officers and directors of Mirant and Southern Company that have or could have been filed. Pursuant to the settlement, Southern Company recorded a charge in the first quarter 2009 of $202 million. This settlement resolves all claims by MC Asset Recovery against Southern Company. Southern Company is currently evaluating potential recovery of the settlement payment through various means including insurance, claims in U.S. Bankruptcy Court, and other avenues. The degree to which any recovery is realized will determine, in part, the final income tax treatment of the settlement payment. The ultimate outcome of any such recovery and/or income tax treatment cannot be determined at this time.

Environmental Matters

New Source Review Actions

In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the NSR provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi Power relating to Gulf Power’s Plant Crist and Mississippi Power’s Plant Watson. In early 2000, the EPA filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants based on the allegations in the notices of violation. However, in March 2001, the Court denied the motion based on lack of jurisdiction, and the EPA has not refiled. The action against Georgia Power has been administratively closed since the spring of 2001, and the case has not been reopened.

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. The consent decree required Alabama Power to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization. It also formalized specific emissions reductions to be accomplished by Alabama Power, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted Alabama Power’s motion for summary judgment and entered final judgment in favor of Alabama Power on the EPA’s claims related to all of the remaining plants: Plants Barry, Gaston, Gorgas, and Greene County.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, where the appeal was stayed, pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007, and in December 2007, the Eleventh Circuit vacated the district court’s decision in the Alabama Power case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case, and the ultimate outcome of these matters cannot be determined at this time.

Southern Company and the traditional operating companies believe they have complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in these matters could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Carbon Dioxide Litigation

New York Case

In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005, but no decision has been issued. The ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village,

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which is alleged to be $95 million to $400 million. In June 2008, all defendants filed motions to dismiss this case. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. The ultimate outcome of this matter cannot be determined at this time.

Environmental Remediation

The registrants must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the subsidiaries may also incur substantial costs to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. Within limits approved by the state PSCs, these rates are adjusted annually or as necessary.

Georgia Power’s environmental remediation liability at March 31, 2009 was $11.4 million. 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 large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and CERCLA NPL are anticipated.

By letter dated September 30, 2008, the EPA advised Georgia Power that it has been designated as a PRP at the Ward Transformer Superfund site located in Raleigh, North Carolina. Numerous other entities have also received notices from the EPA. Georgia Power, along with other named PRPs, is negotiating with the EPA to address cleanup of the site and reimbursement for past expenditures related to work performed at the site. In addition, on April 30, 2009, two PRPs filed separate actions in the U.S. District Court for the Eastern District of North Carolina against numerous other PRPs, including Georgia Power, seeking contribution from the defendants for expenses incurred by the plaintiffs related to work performed at a portion of the site. The ultimate outcome of these matters will depend upon further environmental assessment and the ultimate number of PRPs and cannot be determined at this time; however, it is not expected to have a material impact on Georgia Power’s financial statements.

Gulf Power’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $67.6 million at March 31, 2009. These estimated costs 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 substations. The schedule for completion of the remediation projects will be subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power’s environmental cost recovery clause; therefore, there was no impact on net income as a result of these estimates.

In 2003, the Texas Commission on Environmental Quality (TCEQ) designated Mississippi Power as a potentially responsible party at a site in Texas. The site was owned by an electric transformer company that handled Mississippi Power’s transformers as well as those of many other entities. The site owner is now in bankruptcy and the State of Texas has entered into an agreement with Mississippi Power and several other utilities to investigate and remediate the site. Amounts expensed related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter on Mississippi Power will depend upon further environmental assessment and the ultimate number of potentially responsible parties. The remediation expenses incurred by Mississippi Power are expected

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to be recovered through the ECO Plan. See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — Environmental Compliance.”

The final outcome of these matters cannot now be determined. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, Southern Company, Georgia Power, Gulf Power, and Mississippi Power do not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.

FERC Matters

Market-Based Rate Authority

Each of the traditional operating companies and Southern Power has authorization from 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.

In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by any subsidiary of Southern Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.

In November 2007, the presiding administrative law judge issued an initial decision regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the traditional operating companies and Southern Power to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates and could also result in total refunds of up to $19.7 million, plus interest. The potential refunds include $3.9 million for Alabama Power, $5.8 million for Georgia Power, $0.8 million for Gulf Power, $8.4 million for Mississippi Power, and $0.7 million for Southern Power, in each case plus interest. Southern Company and its subsidiaries believe that there is no meritorious basis for an adverse decision in this proceeding and are vigorously defending themselves in this matter.

In June 2007, the FERC issued its final rule in Order No. 697 regarding market-based rate authority. The FERC generally retained its current market-based rate standards. Responding to a number of requests for rehearing, the FERC issued Order No. 697-A on April 21, 2008 and Order No. 697-B on December 12, 2008. These orders largely affirmed the FERC’s prior revision and codification of the regulations governing market-based rates for public utilities. In accordance with the orders, Southern Company submitted to the FERC an updated market power analysis in September 2008 related to its continued market-based rate authority.

In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction within 30 days. Southern Company commenced the energy auction on April 23, 2009. Implementation of the energy auction in

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accordance with the MBR tariff order is expected to adequately mitigate going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory.

Intercompany Interchange Contract

Southern Company’s generation fleet in its retail service territory is operated under the IIC as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies, Southern Power, and SCS, as agent, under the terms of which the Power Pool is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.

In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. In November 2006, Southern Company filed with the FERC a compliance plan in connection with the order. In April 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan did not have a material impact on Southern Company’s or the traditional operating companies’ financial statements. Southern Power’s annual cost of implementing the compliance plan is approximately $7.0 million. In November 2007, Southern Company notified the FERC that the plan had been implemented. In December 2008, the FERC division of audits issued for public comment its final audit report pertaining to compliance implementation and related matters. No comments challenging the audit report’s findings were submitted. A decision is now pending from the FERC.

Generation Interconnection Agreements

In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, filed complaints at the FERC requesting that the FERC modify the agreements and that those Southern Company subsidiaries refund a total of $19 million previously paid for interconnection facilities, of which $11 million would be refunded by Alabama Power and $8 million by Georgia Power. No other similar complaints are pending with the FERC.

In January 2007, the FERC issued an order granting Tenaska’s requested relief. Although the FERC’s order required the modification of Tenaska’s interconnection agreements, under the provisions of the order, Southern Company determined that no refund was payable to Tenaska. Southern Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection agreements. Tenaska requested rehearing of FERC’s methodology for determining the amount of refunds. The requested rehearings were denied, and Southern Company and Tenaska have appealed the orders to the U.S. Circuit Court for the District of Columbia. The final outcome of this matter cannot now be determined.

Right of Way Litigation

Southern Company and certain of its subsidiaries, including Mississippi Power, have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic

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communications lines on the rights of way that cross the plaintiffs’ properties and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment and seek compensatory and punitive damages and injunctive relief. Management of Southern Company and Mississippi Power believe that they have complied with applicable laws and that the plaintiffs’ claims are without merit.

To date, Mississippi Power has entered into agreements with plaintiffs in approximately 95% of the actions pending against Mississippi Power to clarify its easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit), and dismissals of the related cases are in progress. These agreements have not resulted in any material effects on Southern Company’s or Mississippi Power’s financial statements.

In addition, in late 2001, certain subsidiaries of Southern Company, including Mississippi Power, were named as defendants in a lawsuit brought in Troup County, Georgia, Superior Court by Interstate Fiber Network, a subsidiary of telecommunications company ITC DeltaCom, Inc. that uses rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. Southern Company and Mississippi Power believe that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined.

Nuclear Fuel Disposal Cost Litigation

See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under “Nuclear Fuel Disposal Costs” in Item 8 of the Form 10-K for information regarding the litigation brought by Alabama Power and Georgia Power against the government for breach of contracts related to the disposal of spent nuclear fuel. In July 2007, the U.S. Court of Federal Claims awarded Georgia Power a total of $30 million, based on its ownership interests, and awarded Alabama Power $17.3 million, representing all of the direct costs of the expansion of spent nuclear fuel storage facilities from 1998 through 2004. In August 2007, the government filed a motion for reconsideration, which was denied in November 2007. In January 2008, the government filed a notice of appeal. In February 2008, the government filed a motion to stay the appeal pending the court’s decisions in three other cases already on appeal. In April 2008, the court granted the government’s motion to stay the appeal pending the court’s decisions in three other similar cases already on appeal. Those cases were decided in August 2008. Based on the rulings in those cases, an appeal is expected.

In April 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim), due to the government’s alleged continuing breach of contract. In October 2008, the court denied a similar request by the government to stay this proceeding. The complaint does not contain any specific dollar amount for recovery of

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damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of March 31, 2009 for either claim. The final outcome of these matters cannot be determined at this time; however, no material impact on net income is expected as any damage amounts collected from the government are expected to be returned to customers.

Income Tax Matters

Leveraged Leases

In 2002, the IRS began the examination of three sale-in-lease-out (SILO) transactions entered into by Southern Company. As a result of this examination, the IRS challenged the deductions related to these transactions. Southern Company disagreed with the IRS’s conclusion, went through all administrative appeals, paid approximately $168 million of the additional tax, and sued the IRS for the refund of such taxes.

During the second quarter 2008, decisions in favor of the IRS were reached in several court cases involving other taxpayers with similar leveraged lease investments. Pursuant to the application of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” and FASB Staff Position No. FAS 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction,” management is required to assess on a periodic basis the likely outcome of the uncertain tax positions related to the SILO transactions. Based on these accounting standards and management’s review of the recent court decisions, Southern Company recorded an after-tax charge of approximately $67 million in the second quarter 2008.

In December 2008, Southern Company received from the Commissioner of the IRS an invitation to participate in a global settlement initiative related to the SILO transactions. Southern Company accepted the settlement offer on January 8, 2009. Pursuant to the settlement offer, Southern Company recorded an additional after-tax charge in the fourth quarter 2008 of $16 million. Including the charge recorded in the second quarter 2008, total after-tax charges related to settling the SILO litigation amounted to $83 million in 2008. Of the total, approximately $7 million represents interest and $76 million represents non-cash charges related to the reallocation of lease income and will be recognized in income over the remaining term of the affected leases. All additional taxes due as a result of the settlement have now been paid. A final closing agreement with the IRS is currently being negotiated and is expected to be completed in the second quarter 2009.

Georgia State Income Tax Credits

Georgia Power’s 2005 through 2008 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power has also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, these claims could have a significant, and possibly material, positive effect on Southern Company’s and Georgia Power’s net income. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Southern Company’s and Georgia Power’s cash flow. The ultimate outcome of this matter cannot now be determined.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(C)	FAIR VALUE MEASUREMENTS
	As of March 31, 2009, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, are as follows:

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of March 31, 2009:	(Level 1)		(Level 2)		(Level 3)		Total
			(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	20	$	—	$	20
Nuclear decommissioning trusts(a)		413		394		—		807
Cash equivalents and restricted cash		697		—		—		697
Other		3		46		32		81
Total	$	1,113	$	460	$	32	$	1,605
Liabilities:
Energy-related derivatives	$	—	$	443	$	—	$	443
Interest rate derivatives		—		18		—		18
Total	$	—	$	461	$	—	$	461
Alabama Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Nuclear decommissioning trusts(a)		208		167		—		375
Cash equivalents and restricted cash		347		—		—		347
Total	$	555	$	168	$	—	$	723
Liabilities:
Energy-related derivatives	$	—	$	131	$	—	$	131
Interest rate derivatives		—		11		—		11
Total	$	—	$	142	$	—	$	142
Georgia Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Nuclear decommissioning trusts(a)		205		227		—		432
Cash equivalents and restricted cash		151		—		—		151
Total	$	356	$	228	$	—	$	584
Liabilities:
Energy-related derivatives	$	—	$	178	$	—	$	178
Interest rate derivatives		—		7		—		7
Total	$	—	$	185	$	—	$	185
Gulf Power
Assets:
Cash equivalents and restricted cash	$	55	$	—	$	—	$	55
Liabilities:
Energy-related derivatives	$	—	$	43	$	—	$	43
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Cash equivalents		19		—		—		19
Total	$	19	$	2	$	—	$	21
Liabilities:
Energy-related derivatives	$	—	$	78	$	—	$	78

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of March 31, 2009:	(Level 1)		(Level 2)		(Level 3)		Total
			(in millions)
Southern Power
Assets:
Energy-related derivatives	$	—	$	16	$	—	$	16
Cash equivalents		29		—		—		29
Total	$	29	$	16	$	—	$	45
Liabilities:
Energy-related derivatives	$	—	$	13	$	—	$	13

(a) Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.

Energy-related derivatives and interest rate derivatives primarily consist of over-the-counter contracts. See Note (F) under “Financial Instruments” herein for additional information. The nuclear decommissioning trust funds are invested in a diversified mix of equity and fixed income securities. The cash equivalents and restricted cash consist of securities with original maturities of 90 days or less. “Other” represents marketable securities and certain deferred compensation funds also invested in various marketable securities. All of these financial instruments and investments are valued primarily using the market approach.

Changes in the fair value measurement of the Level 3 items using significant unobservable inputs for Southern Company at March 31, 2009 are as follows:

	Level 3
	Other
	(in millions)
Beginning balance at December 31, 2008	$	35
Total gains (losses) — realized/unrealized:
Included in earnings		(3	)
Included in other comprehensive income		—
Ending balance at March 31, 2009	$	32

Unrealized losses of $3 million were included in earnings during the period relating to assets still held at March 31, 2009 and are recorded in “depreciation and amortization.”

Southern Company, Alabama Power, and Georgia Power continue to elect the fair value option under FASB Statement No. 159, “Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115” for investment securities held in the nuclear decommissioning trust funds. For the three months ended March 31, 2009, the reduction in fair value of the funds, which includes reinvested interest and dividends, is recorded in the regulatory liability, and was $23 million for Alabama Power, $25 million for Georgia Power, and $48 million for Southern Company.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(D)	CONSTRUCTION PROJECTS
	Integrated Coal Gasification Combined Cycle
	See Note 3 to the financial statements of Southern Company and Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K for information regarding the Kemper IGCC.
	On April 6, 2009, the Governor of the State of Mississippi signed into law a bill that will provide an ad valorem tax exemption for a portion of the assessed value of all property utilized in certain electric generating facilities with integrated gasification process facilities. This tax exemption, which may not exceed 50% of the total value of the project, is for projects with a capital investment from private sources of $1 billion or more.
	On April 6, 2009, Mississippi Power received an accounting order from the Mississippi PSC directing Mississippi Power to continue to charge all Kemper IGCC generation resources planning, evaluation, and screening costs to regulatory assets including those costs associated with activities to obtain a certificate of public convenience and necessity and costs necessary and prudent to preserve the availability, economic viability, and/or required schedule of the selected generation resource until the Mississippi PSC makes findings and determination as to the recovery of Mississippi Power’s prudent expenditures.
	As of March 31, 2009, Mississippi Power had spent a total of $50.7 million associated with Mississippi Power’s generation resource planning, evaluation, and screening activities, including regulatory filings costs. Costs incurred during the first quarter 2009 totaled $8.4 million as compared to $7.2 million during the first quarter 2008. Of the total $50.7 million, $46.2 million was deferred in other regulatory assets, $3.7 million was related to land purchases capitalized, and $0.8 million was previously expensed.
	Several motions have been filed by intervenors in this proceeding, most of which are procedural in nature and seek to stay or delay the timely and orderly administration of the docket. In addition to these procedural motions, a motion has been filed by the Attorney General for the State of Mississippi which questions whether the Mississippi PSC has authority to approve the gasification portion of the Kemper IGCC. All of these motions were heard by the Mississippi PSC on May 5, 2009.
	The ultimate outcome of these matters cannot now be determined.
	Nuclear
	See Note 3 to the financial statements of Southern Company and Georgia Power under “Nuclear” in Item 8 of the Form 10-K for information regarding the potential expansion of Plant Vogtle.
	On March 17, 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 at an in-service cost of $6.4 billion. In addition, the Georgia PSC voted to approve inclusion of the related construction work in progress accounts in rate base and to recover financing costs during the construction period beginning in 2011.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

	On April 21, 2009, the Governor of the State of Georgia signed into law The Georgia Nuclear Energy Financing Act that will allow Georgia Power to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period. The cost recovery provisions will become effective January 1, 2011.
(E)	COMMON STOCK
	For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to exercised options and outstanding options under the stock option plan. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for further information on the stock option plan. The effect of the stock options was determined using the treasury stock method. Shares used to compute diluted earnings per share are as follows (in thousands):

	Three Months		Three Months
	Ended		Ended
	March 31, 2009		March 31, 2008
As reported shares		779,858		766,150
Effect of options		1,787		4,171
Diluted shares		781,645		770,321

(F)	FINANCING
	Bank Credit Arrangements
	At March 31, 2009, unused credit arrangements with banks totaled $4.2 billion, of which $775 million expires during 2009, $160 million expires in 2010, $25 million expires in 2011, and $3.2 billion expires in 2012. These credit arrangements provided liquidity support to the registrants’ commercial paper programs and the traditional operating companies’ variable rate pollution control revenue bonds. The following table outlines the credit arrangements by company:

					Executable
					Term-Loans					Expires
					One			Two
Company	Total		Unused		Year			Years		2009		2010		2011		2012
							(in millions)
Southern Company	$	950	$	950	$	—		$	—	$	—	$	—	$	—	$	950
Alabama Power		1,256		1,256		379			—		466		—		25		765
Georgia Power		1,290		1,278		—			40		40		130		—		1,120
Gulf Power		140		140		60			—		110		30		—		—
Mississippi Power		109		109		15			54		109		—		—		—
Southern Power		400		400		—			—		—		—		—		400
Other		50		50		50			—		50		—		—		—
Total	$	4,195	$	4,183	$	504		$	94	$	775	$	160	$	25	$	3,235

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Subsequent to March 31, 2009, Georgia Power, Gulf Power, and Mississippi Power entered into additional committed credit arrangements resulting in a net increase of $425 million, $75 million, and $40 million, respectively, to enhance liquidity. These additional credit arrangements all expire in 2010.

See Note 6 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K for additional information.

Changes in Equity

The following table presents year-to-date changes in stockholders’ equity and redeemable preferred stock of subsidiaries:

				Preferred
				and					Redeemable
	Common			Preference		Total			Preferred
	Stockholders’			Stock of		Stockholders’			Stock of
	Equity			Subsidiaries		Equity			Subsidiaries
	(in millions)
Balance at December 31, 2008	$	13,276		$	707	$	13,983		$	375
Net income		142			-		142		—
Other comprehensive income (loss)		8			-		8		—
Stock issued		170			-		170		—
Cash dividends		(343	)		-		(343	)	—
Balance at March 31, 2009	$	13,253		$	707	$	13,960		$	375

				Preferred
				and					Redeemable
	Common			Preference		Total			Preferred
	Stockholders’			Stock of		Stockholders’			Stock of
	Equity			Subsidiaries		Equity			Subsidiaries
	(in millions)
Balance at December 31, 2007	$	12,385		$	707	$	13,092		$	498
Net income		375			-		375		—
Other comprehensive income (loss)		(22	)		-		(22	)	—
Stock issued		154			-		154		—
Cash dividends		(325	)		-		(325	)	—
Redemption of preferred stock		-			-		-			(125	)
Other		(4	)		-		(4	)	—
Balance at March 31, 2008	$	12,563		$	707	$	13,270		$	373

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Financial Instruments

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, each company nets their exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the companies’ policies in areas such as counterparty exposure and risk management practices. The registrants’ 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. FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133) requires companies to recognize all derivative instruments as either assets or liabilities at fair value in the statement of financial position.

Energy-Related Derivatives

The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts. Southern Power also has limited exposure to market volatility in commodity fuel prices and prices of electricity 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 sales of uncontracted generating capacity.

To mitigate residual risks relative to movements in electricity prices, the registrants enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the registrants may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

Energy-related derivative contracts are accounted for in one of three methods:

• Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional operating companies’ 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.

• SFAS No. 133 Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges, which are mainly used by Southern Power, to hedge anticipated purchases and sales are initially deferred in other comprehensive income before being recognized in 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.

132

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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 industry. 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 March 31, 2009, the net volume of energy-related derivative contracts for power and natural gas positions for the registrants, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions, and the longest date for derivatives not designated as hedges, were as follows:

	Power						Gas
			Longest		Longest		Net			Longest		Longest
As of March 31,	Net Sold		Hedge		Non-Hedge		Purchased			Hedge		Non-Hedge
2009:	MWH		Date		Date		Bcf			Date		Date
	(in thousands)
Southern Company		1,172		2009		2010		173	*		2012		2010
Alabama Power		—		—		2009		49			2012		—
Georgia Power		—		—		2009		71			2012		—
Gulf Power		—		—		2009		16			2012		—
Mississippi Power		500		2009		2009		30			2012		2009
Southern Power		672		—		2010		6	*		—		2010

           * Includes location basis of 2 Bcf.

For cash flow hedges, the amounts expected to be reclassified from other comprehensive income to revenue and fuel expense for the next 12-month period ending March 31, 2010 are immaterial for all registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries also enter into interest rate derivatives, which include forward-starting interest rate swaps, to hedge exposure to changes in interest rates. Derivatives related to fixed-rate securities are accounted for as fair value hedges. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

For fair value hedges under SFAS No. 133, the changes in the fair value of the hedging derivatives are recorded in earnings and are offset by the changes in the fair value of the hedged item. For other hedges qualifying as cash flow hedges under SFAS No. 133, the fair value gains or losses are recorded in other comprehensive income and are reclassified into earnings at the same time the hedged transactions affect earnings.

133

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At March 31, 2009, Southern Company had a total of $1.2 billion notional amount of interest rate derivatives outstanding with net fair value losses of $18 million as follows:

				Weighted				Fair Value
				Average				Gain (Loss)
	Notional		Variable Rate	Fixed Rate			Hedge Maturity	March 31,
Registrant	Amount		Received	Paid			Date	2009
	(in millions)							(in millions)
Cash flow hedges of existing debt
Alabama Power	$	576	SIFMA* Index		2.69	%	February 2010	$	(11	)
Georgia Power		301	SIFMA* Index		2.22	%	December 2009		(3	)
Georgia Power		300	1-month LIBOR		2.43	%	April 2010		(4	)
Total	$	1,177						$	(18	)

           * Securities Industry and Financial Markets Association Municipal Swap Index (SIFMA)

For the three months ended March 31, 2009, Georgia Power incurred net losses of $(16) million upon termination of certain interest rate derivatives at the same time it issued debt. The effective portion of these losses has been deferred in other comprehensive income and will be amortized to interest expense over the life of the original interest rate derivative, reflecting the period in which the forecasted hedged transaction affects earnings.

The following table reflects the estimated pre-tax gains (losses) that will be reclassified from other comprehensive income to interest expense for the next 12-month period ending March 31, 2010, together with the longest date that total deferred gains and losses are expected to be amortized into earnings.

	Estimated Gain (Loss) to
	be Reclassified for the			Total Deferred
	12 Months Ending			Gains (Losses)
Registrant	March 31, 2010			Amortized Through
	(in millions)
Southern Company	$	(36	)		2037
Alabama Power		(10	)		2035
Georgia Power		(15	)		2037
Gulf Power		(1	)		2018
Southern Power		(10	)		2016

134

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Derivative Financial Statement Presentation and Amounts

At March 31, 2009, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at March 31, 2009
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives
Other, deferred charges and other assets	$	2	$	1	$	1	$	—	$	—		N/A
Derivatives designated as hedging instruments under SFAS No. 133
Energy-related derivatives
Other, current assets	$	1	$	—	$	—	$	—	$	1	$	—
Derivatives not designated as hedging instruments under SFAS No. 133
Energy-related derivatives
Other, current assets*	$	16	$	—	$	—	$	—	$	1	$	—
Assets from risk management activities		—		—		—		—		—		15
Other, deferred charges and other assets		1		—		—		—		—		1
Total derivatives not designated as hedging instruments under SFAS No. 133	$	17	$	—	$	—	$	—	$	1	$	16
Total asset derivatives	$	20	$	1	$	1	$	—	$	2	$	16

           * Southern Company includes Assets from risk management activities in Other, current assets.

Liability Derivatives at March 31, 2009
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives
Liabilities from risk management activities	$	323	$	106	$	136	$	35	$	46
Other, deferred credits and other liabilities		106		25		42		8		31
Total derivatives designated as hedging instruments for regulatory purposes	$	429	$	131	$	178	$	43	$	77		N/A
Derivatives designated as hedging instruments under SFAS No. 133
Interest rate derivatives
Liabilities from risk management activities	$	18	$	11	$	7	$	—	$	—	$	—
Derivatives not designated as hedging instruments under SFAS No. 133
Energy-related derivatives
Liabilities from risk management activities	$	14	$	—	$	—	$	—	$	1	$	13
Total liability derivatives	$	461	$	142	$	185	$	43	$	78	$	13

135

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

All derivative instruments are measured at fair value. See Note (C) herein for additional information.

At March 31, 2009, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheet were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet
Derivative Category and Balance Sheet	Southern			Alabama			Georgia			Gulf			Mississippi
Location	Company			Power			Power			Power			Power
							(in millions)
Energy-related derivatives
Other regulatory assets, current	$	(323	)	$	(106	)	$	(136	)	$	(35	)	$	(46	)
Other regulatory assets, deferred		(106	)		(25	)		(42	)		(8	)		(31	)
Other regulatory liabilities, deferred		2			1			1			—			—
Total energy-related derivative gains (losses)	$	(427	)	$	(130	)	$	(177	)	$	(43	)	$	(77	)

For the three months ended March 31, 2009 and March 31, 2008, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

	Gain (Loss)
Derivatives in SFAS No. 133	Recognized in OCI						Gain (Loss) Reclassified from Accumulated OCI
Cash Flow Hedging	on Derivative						into Income (Effective Portion)
Relationships	(Effective Portion)						Statements of Income Location	Amount
	2009			2008				2009			2008
			(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	1		$	(12	)	Fuel	$	—		$	—
Interest rate derivatives		1			(24	)	Interest expense		(10	)		(5	)
Total	$	2		$	(36	)		$	(10	)	$	(5	)
Alabama Power
Energy-related derivatives	$	—		$	(1	)	Fuel	$	—		$	—
Interest rate derivatives		(2	)		(5	)	Interest expense		(3	)		—
Total	$	(2	)	$	(6	)		$	(3	)	$	—
Georgia Power
Interest rate derivatives total	$	3		$	(16	)	Interest expense	$	(5	)	$	(1	)
Gulf Power
Interest rate derivatives total	$	—		$	(4	)	Interest expense	$	—		$	—
Mississippi Power
Energy-related derivatives total	$	—		$	(3	)	Fuel	$	—		$	—
Southern Power
Energy-related derivatives	$	1		$	(8	)	Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense		(2	)		(4	)
Total	$	1		$	(8	)		$	(2	)	$	(4	)

There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

136

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the three months ended March 31, 2009 and March 31, 2008, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:

Derivatives not Designated as Hedging	Unrealized Gain (Loss) Recognized in Income
Instruments Under SFAS No. 133	Statements of Income Location	Amount
			2009		2008
		(in millions)
Southern Company
Energy-related derivatives	Wholesale revenues	$	4		$	(28	)
	Fuel		(4	)		12
	Purchased power		(1	)		2
Total		$	(1	)	$	(14	)
Southern Power
Energy-related derivatives	Wholesale revenues	$	4		$	(28	)
	Fuel		(4	)		12
	Purchased power		(1	)		2
Total		$	(1	)	$	(14	)

Contingent Features

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At March 31, 2009, the fair value of derivative liabilities with contingent features, by registrant, is as follows:

	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
	Company		Power		Power		Power		Power		Power
					(in millions)
Derivative liabilities	$	82	$	25	$	40	$	6	$	9	$	2

At March 31, 2009, the registrants had no collateral posted with their derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, is $82 million for each registrant.

Currently, each of the registrants has investment grade credit ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and/or preference stock.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. For the traditional operating companies and Southern Power, included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade.

137

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(G)	RETIREMENT BENEFITS
	Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the plan are expected for the year ending December 31, 2009. 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 operating companies fund related trusts to the extent required by their respective regulatory commissions.
	See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K. Components of the pension plans’ and postretirement plans’ net periodic costs for the three-month periods ended March 31, 2009 and 2008 are as follows (in millions):

	Southern			Alabama			Georgia			Gulf			Mississippi
PENSION PLANS	Company			Power			Power			Power			Power
Three Months Ended March 31, 2009
Service cost	$	36		$	8		$	12		$	2		$	2
Interest cost		97			24			37			4			4
Expected return on plan assets		(135	)		(41	)		(54	)		(6	)		(5	)
Net amortization		10			3			4			—			—
Net cost (income)	$	8		$	(6	)	$	(1	)	$	—		$	1
Three Months Ended March 31, 2008
Service cost	$	36		$	9		$	12		$	2		$	2
Interest cost		87			22			33			4			4
Expected return on plan assets		(131	)		(40	)		(53	)		(6	)		(5	)
Net amortization		12			3			5			—			—
Net cost (income)	$	4		$	(6	)	$	(3	)	$	—		$	1

	Southern			Alabama			Georgia			Gulf		Mississippi
POSTRETIREMENT PLANS	Company			Power			Power			Power		Power
Three Months Ended March 31, 2009
Service cost	$	7		$	2		$	2		$	—	$	1
Interest cost		28			7			13			1		1
Expected return on plan assets		(15	)		(6	)		(8	)		—		—
Net amortization		7			2			4			—		—
Net cost (income)	$	27		$	5		$	11		$	1	$	2
Three Months Ended March 31, 2008
Service cost	$	7		$	2		$	2		$	—	$	—
Interest cost		28			7			12			1		1
Expected return on plan assets		(15	)		(5	)		(7	)		—		—
Net amortization		8			2			4			—		—
Net cost (income)	$	28		$	6		$	11		$	1	$	1

138

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(H)	EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS
	Effective Tax Rate
	Southern Company’s effective tax rate was 54.1% for the three months ended March 31, 2009, as compared to 32.2% for the same period in 2008. See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for information on the effective income tax rate. Southern Company’s effective tax rate increased for the three months ended March 31, 2009 primarily due to the $202 million charge recorded for the MC Asset Recovery settlement. Southern Company is currently evaluating potential recovery of the settlement payment through various means including insurance, claims in U.S. Bankruptcy Court, and other avenues. The degree to which any recovery is realized will determine, in part, the final income tax treatment of the settlement payment. See Note (B) herein under “Mirant Matters” for further information regarding this matter.
	Unrecognized Tax Benefits
	Changes during 2009 for unrecognized tax benefits are as follows:

	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
	Company		Power		Power		Power		Power		Power		Total
	(in millions)
Unrecognized tax benefits as of December 31, 2008	$	3.7	$	3.0	$	137.1	$	0.3	$	1.8	$	0.5	$	146.4
Tax positions from current periods		0.1		0.2		11.5		—		—		0.1		11.9
Tax positions from prior periods		—		—		1.7		—		—		—		1.7
Reductions due to settlements		—		—		—		—		—		—		—
Reductions due to expired statute of limitations		—		—		—		—		—		—		—
Balance as of March 31, 2009	$	3.8	$	3.2	$	150.3	$	0.3	$	1.8	$	0.6	$	160.0

The tax positions increase from the current periods relates primarily to the Georgia state tax credits litigation and other miscellaneous uncertain tax positions. See Note (B) herein under “Income Tax Matters — Georgia State Income Tax Credits” for additional information.

Impact on Southern Company’s effective tax rate, if recognized, is as follows:

					As of		As of
	Georgia		Other		March 31,		December 31,
	Power		Registrants		2009		2008		Change
	(in millions)
Tax positions impacting the effective tax rate	$	147.5	$	9.7	$	157.2	$	143.5	$	13.7
Tax positions not impacting the effective tax rate		2.8		—		2.8		2.9		(0.1	)
Balance of unrecognized tax benefits	$	150.3	$	9.7	$	160.0	$	146.4	$	13.6

Accrued interest for unrecognized tax benefits:

	(in millions)
Interest accrued as of December 31, 2008	$	14.8
Interest accrued during the period		2.5
Balance as of March 31, 2009	$	17.3

139

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

	It is reasonably possible that the amount of the unrecognized benefit with respect to a majority of Southern Company’s and Georgia Power’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The possible settlement of the Georgia state tax credits litigation would substantially reduce the balances. The conclusion or settlement of federal or state audits could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
(I)	SEGMENT AND RELATED INFORMATION
	Southern Company’s reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Southern Power’s revenues from sales to the traditional operating companies were $135 million and $133 million for the three months ended March 31, 2009 and March 31, 2008, respectively. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications, energy-related services, and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services are as follows:

	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
	(in millions)
Three Months Ended March 31, 2009:
Operating revenues	$	3,558	$	232	$	(151	)	$	3,639	$	44		$	(17	)	$	3,666
Segment net income (loss) after dividends on preferred and preference stock of subsidiaries		302		28		—			330		(205	)		1			126
Total assets at March 31, 2009	$	46,050	$	2,787	$	(93	)	$	48,744	$	1,382		$	(569	)	$	49,557

	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
	(in millions)
Three Months Ended March 31, 2008:
Operating revenues	$	3,618	$	216	$	(185	)	$	3,649	$	48		$	(14	)	$	3,683
Segment net income (loss) after dividends on preferred and preference stock of subsidiaries		342		29		—			371		(10	)		(2	)		359
Total assets at December 31, 2008	$	44,794	$	2,813	$	(139	)	$	47,468	$	1,407		$	(528	)	$	48,347

Products and Services

	Electric Utilities’ Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended March 31, 2009	$	3,065	$	451	$	123	$	3,639
Three Months Ended March 31, 2008	$	3,006	$	514	$	129	$	3,649

140

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.

Item 1A. Risk Factors.

See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. There have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

141

Item 6. Exhibits.

(4) Instruments Describing Rights of Security Holders, Including Indentures

Alabama Power
(b)1	-	Forty-Third Supplemental Indenture to Senior Note Indenture dated as of March 6, 2009, providing for the issuance of the Series 2009A 6.00% Senior Notes due March 1, 2039. (Designated in Form 8-K dated February 26, 2009, File No. 1-3164, as Exhibit 4.2.)
Georgia Power
(c)1	-	Thirty-Eighth Supplemental Indenture to Senior Note Indenture dated as of February 10, 2009, providing for the issuance of the Series 2009A 5.95% Senior Notes due February 1, 2039. (Designated in Form 8-K dated February 4, 2009, File No. 1-6468, as Exhibit 4.2.)
Mississippi Power
(e)1	-	Tenth Supplemental Indenture to Senior Note Indenture dated as of March 6, 2009, providing for the issuance of the 2009A 5.55% Senior Notes due March 1, 2019. (Designated in Form 8-K dated March 3, 2009, File No. 001-11229, as Exhibit 4.2.)
(10) Material Contracts
Southern Company
(a)1	-	Form of 2009 Stock Option Award Agreement for Executive Officers of Southern Company under the Southern Company Omnibus Incentive Compensation Plan.
Gulf Power
(d)1	-	Power Purchase Agreement between Gulf Power and Shell Energy North America (US), L.P. dated March 16, 2009. (Gulf Power has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Gulf Power has omitted such portions from this filing and filed them separately with the SEC.)
(24) Power of Attorney and Resolutions
Southern Company
(a)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 1-3526 as Exhibit 24(a) and incorporated herein by reference.)
Alabama Power
(b)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 1-3164 as Exhibit 24(b) and incorporated herein by reference.)
Georgia Power
(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 1-6468 as Exhibit 24(c) and incorporated herein by reference.)
(c)2	-	Power of Attorney for Ronnie R. Labrato.

142

Gulf Power
(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 0-2429 as Exhibit 24(d) and incorporated herein by reference.)
Mississippi Power
(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 001-11229 as Exhibit 24(e) and incorporated herein by reference.)
Southern Power
(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 333-98553 as Exhibit 24(f) and incorporated herein by reference.)
(31) Section 302 Certifications
Southern Company
(a)1	-	Certificate of Southern Company’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(a)2	-	Certificate of Southern Company’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Alabama Power
(b)1	-	Certificate of Alabama Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(b)2	-	Certificate of Alabama Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Georgia Power
(c)1	-	Certificate of Georgia Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(c)2	-	Certificate of Georgia Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Gulf Power
(d)1	-	Certificate of Gulf Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(d)2	-	Certificate of Gulf Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

143

Mississippi Power
(e)1	-	Certificate of Mississippi Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(e)2	-	Certificate of Mississippi Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Southern Power
(f)1	-	Certificate of Southern Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(f)2	-	Certificate of Southern Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(32) Section 906 Certifications
Southern Company
(a)	-	Certificate of Southern Company’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Alabama Power
(b)	-	Certificate of Alabama Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Georgia Power
(c)	-	Certificate of Georgia Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Gulf Power
(d)	-	Certificate of Gulf Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Mississippi Power
(e)	-	Certificate of Mississippi Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Southern Power
(f)	-	Certificate of Southern Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

144

THE SOUTHERN COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

	THE SOUTHERN COMPANY
By	David M. Ratcliffe
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	W. Paul Bowers
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Wayne Boston
	(Wayne Boston, Attorney-in-fact)

Date: May 7, 2009

145

ALABAMA POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

	ALABAMA POWER COMPANY
By	Charles D. McCrary
	President and Chief Executive Officer
	(Principal Executive Officer)
By	Art P. Beattie
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Wayne Boston
	(Wayne Boston, Attorney-in-fact)

Date: May 7, 2009

146

GEORGIA POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

	GEORGIA POWER COMPANY
By	Michael D. Garrett
	President and Chief Executive Officer
	(Principal Executive Officer)
By	Ronnie R. Labrato
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Wayne Boston
	(Wayne Boston, Attorney-in-fact)

Date: May 7, 2009

147

GULF POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

	GULF POWER COMPANY
By	Susan N. Story
	President and Chief Executive Officer
	(Principal Executive Officer)
By	Philip C. Raymond
	Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Wayne Boston
	(Wayne Boston, Attorney-in-fact)

Date: May 7, 2009

148

MISSISSIPPI POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

	MISSISSIPPI POWER COMPANY
By	Anthony J. Topazi
	President and Chief Executive Officer
	(Principal Executive Officer)
By	Frances Turnage
	Vice President, Treasurer, and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Wayne Boston
	(Wayne Boston, Attorney-in-fact)

Date: May 7, 2009

149

SOUTHERN POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

	SOUTHERN POWER COMPANY
By	Ronnie L. Bates
	President and Chief Executive Officer
	(Principal Executive Officer)
By	Michael W. Southern
	Senior Vice President, Treasurer, and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Wayne Boston
	(Wayne Boston, Attorney-in-fact)

Date: May 7, 2009

150

EX-10

Exhibit 10(a)1

SOUTHERN COMPANY

OMNIBUS INCENTIVE COMPENSATION PLAN

FORM OF STOCK OPTION AWARD AGREEMENT

FOR EXECUTIVE OFFICERS OF THE SOUTHERN COMPANY

Your Options are subject to the following terms and conditions:

1. Grant: The Southern Company (the “Company”) Compensation and Management Succession Committee (the “Committee”) has granted you nonqualified stock options (the “Options”) to purchase shares of Southern Company common stock (“Common Stock”). This award is governed by the 2006 Southern Company Omnibus Incentive Compensation Plan, as amended from time to time (the “Plan”).

2. Terms: Terms used in this Award Agreement that are defined in the Plan will have the meanings ascribed to them in the Plan. If there is any inconsistency between the terms of this Award Agreement and the terms of the Plan, the Plan’s terms will supersede and replace the conflicting terms of this Award Agreement.

3. Grant Date, Number of Shares and Grant Price: The Grant Date of your Options is ______, the number of shares granted to you under your Options is _______ and the Grant Price (also referred to as the Exercise Price per share) is _______. This information is also set forth on the UBS Financial Services Inc. website at https://onesource.ubs.com/so. The Grant Price is equal to the closing price of a share of Common Stock on the Grant Date.

4. Option Term: The Options have been granted for a period of ten (10) years from the Grant Date (the “Option Term”).

5. Vesting and Exercise: Options do not provide you with any rights or interests until they vest (become exercisable). One-third of the shares granted under the Options shall vest on each one year anniversary of the Grant Date.

6. How to Exercise: You may exercise an Option by entering and executing an exercise order with UBS Financial Services Inc. and obtaining an exercise confirmation. UBS Financial Services Inc. may be reached by telephone at 404-760-3312 or 1-866-4SO-OPTION (1-866-476-6784) or on the UBS Financial Services Inc. website at https://onesource.ubs.com/so. Payment for shares you elect to purchase may be made in cash or in any other form of payment allowed by the Company. Should you decide to purchase Common Stock pursuant to the exercise of an Option with previously purchased Common Stock (if allowed), any such Common Stock used as payment will be valued at its Fair Market Value as of the date of exercise of the Option.

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7. Impact of Termination of Employment

The vesting and term of any Options will change if you terminate employment, according to the following table:

Termination of Employment Event	Impact on Unvested Options	Exercise Period for Vested Options (But in No Event Beyond the Original Option Term )
Disability 1	Vest fully	3 years
Retirement 2	See below	5 years
Death	Vest fully	3 years
Any other type of termination not for cause3	Forfeited	90 days
Any termination for cause3/4	Forfeited	Forfeited

¹Disability means any physical or mental condition which would qualify you for a disability benefit under the long-term disability plan maintained by the Company and applicable to you, or if no such disability plan exists, as determined by the Committee.

²Retirement means any retirement under the Southern Company Pension Plan.

³Cause is determined by the Committee.

⁴Any termination for cause includes any type of termination (including, but not limited to, a voluntary or involuntary resignation by you, a voluntary or involuntary termination by the Company, your termination with severance, your retirement, or your termination because of a disability) if such termination is related to cause.

Except for Retirement, Options that are not, and do not, become exercisable at the time of your termination of employment will, coincident therewith, terminate and be of no force or effect.

Upon your Retirement, all Options that are not exercisable as of the date of your Retirement shall become fully vested and all Options shall remain exercisable until the earlier of (1) 5 years from your Retirement or (2) the Option Term; provided, however, that if within two years following your Retirement you become directly or indirectly employed by a Peer Company, all Options that are unvested or were unvested immediately prior to your Retirement shall immediately be forfeited. Upon request, you must provide written information regarding your employer (if any) within two years following your Retirement and confirm that you are not employed by a Peer Company. If you (1) fail to provide the above information as requested or (2) become directly or indirectly employed with a Peer Company within two years following your Retirement, all unvested Options and all Options that vested upon Retirement shall be immediately forfeited and, to the extent any of such Options have been exercised, you must repay an amount equal to any gain realized from such exercise to the Company within 60 days after you are notified that repayment is required. If you do not repay such amount within 60 days, the Company may set-off the amount of any such gain against any amount owed to you by the Company or an affiliate. “Peer Company” means any company or entity engaged in the generation, distribution, marketing and/or sale of electricity.

2

If you die within the post-Retirement period for exercise, all outstanding Options will vest immediately and your executor or administrator or other authorized person will have 3 years from the date of your death to exercise (subject to the expiration of the original 10-year term of the Options).

8. Transferability: Options are not transferable except by will or the laws of descent and distribution and may be exercised during your life only by you or, following your death or disability if any Options are still exercisable, by your duly appointed guardian or other legal representative.

Notwithstanding the above, if you are a designated “executive officer”, as that term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, of Southern Company (but not of a Southern Company subsidiary) at the time of transfer (or, if your employment has terminated at the time of transfer, at the time of your termination), Options may be transferred to your immediate family (spouse, children, or grandchildren), a trust for the benefit of your immediate family, or a partnership or limited liability company whose only partners or members are you or your immediate family (any such recipient to be referred to as a “Transferee”), provided such transfer is not a transfer for value for federal income tax purposes. Subsequent transfer or assignment by a Transferee is prohibited and any such attempt will be disregarded as void. Please provide prior notice of any transfer to the Senior Vice President, Human Resource and Chief Diversity Officer. Transfers incident to a divorce are not allowed.

9. Other Terms and Conditions. The Design Details, an administrative document adopted by the Committee which is set forth on the UBS Financial Services Inc. website at https://onesource.ubs.com/so, contains additional provisions that apply to the Options. Additionally, the Options are subject to all of the terms and conditions set forth in the Plan and any other administrative documents adopted by the Committee. By exercising any portion of the Options, you agree to be subject to all of the terms and conditions of this Award Agreement. Additionally, you agree to be subject to all of the terms and conditions of the Plan, the Design Details, and any other administrative documents, as amended from time to time.

10. Additional Information: Please refer any questions you may have regarding these Options to UBS Financial Services Inc. at 404-760-3312 or 1-866-4SO-OPTION or HR Direct at 1-888-678-6787.

I have read and understand the foregoing and hereby accept the referenced grant of Options subject to the terms and conditions described herein.

NAME

Date

3

EX-10

Exhibit 10(d)1

Gulf Power Company has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the Securities and Exchange Commission. Gulf Power Company has omitted portions from this filing and filed them separately with the Securities and Exchange Commission. Such omissions are designated as “[**]”.

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POWER PURCHASE AGREEMENT

DATED March 16, 2009

SHELL ENERGY NORTH AMERICA (US), L.P.

AND

GULF POWER COMPANY

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TABLE OF CONTENTS

Page

ARTICLE 1 DEFINED TERMS; INTERPRETATION 7

1.1 Defined Terms 7

1.2 Interpretation 30

ARTICLE 2 [NOT USED] 31

ARTICLE 3 PLANT FACILITIES AND EQUIPMENT 31

3.1 The Plant 31

3.2 Energy Metering Equipment 31

3.3 Communications and Telemetry Equipment 32

ARTICLE 4 CAPACITY PAYMENTS; CAPACITY TESTS 32

4.1 Capacity Payments 32

4.2 Initial Contract Capacity 33

4.3 Annual Test to Set Contract Capacity 33

4.4 Right to Observe Tests 34

4.5 Additional Tests 35

4.6 Test Fuel and Delivered Energy 35

ARTICLE 5 ENERGY PURCHASES AND PAYMENTS 35

5.1 Energy Purchases 35

5.2 Requests for Energy 36

5.3 Ancillary Services 36

5.4 Delivered Energy Payments 36

5.5 Oil-Generated Energy Surcharge Payments. 37

5.6 Power Augmentation Surcharge Payments; Reimbursement for Fuel Usage. 37

5.7 Cover Options. 37

5.8 Exclusivity. 42

5.9 Shell’s Option to Withhold a Limited Amount of Energy. 42

5.10 Pre-Term Activities. 43

ARTICLE 6 FUEL SUPPLIES AND DELIVERIES 43

6.1 Gas Deliveries 43

6.2 Fuel Oil Deliveries 47

6.3 Intentionally Omitted 49

ARTICLE 7 OPERATION OF THE PLANT 49

7.1 Maintenance Scheduling 49

7.2 Requests for Energy 51

7.3 Response to Non-Conforming Requests for Energy. 52

7.4 Operation. 52

7.5 Operating Committee. 53

7.6 Tenaska ECA Amendment 53

7.7 Transmission Service to Deliver Energy and Capacity from the Energy Delivery Point. 53

7.8 Transmission Interconnection Service to the Energy Delivery Point. 53

ARTICLE 8 OTHER PAYMENTS; TAXES 54

8.1 [Intentionally Omitted] 54

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8.2 Payments for Start Up Energy 54

8.3 Heat Rate 54

8.4 Payments for Steam Turbine Starts 57

8.5 Combustion Turbine Fired Hour Payments 59

8.6 Bonus Availability Target and Availability Bonus Payments 61

8.7 Peak Availability Target and Peak Availability Payments 61

8.8 Off Peak Availability Target and Off Peak Availability Payments 62

8.9 Limitation on Availability Payments; Nature of Availability Payments 64

8.10 Energy Imbalance Charges

8.11 Taxes 65

ARTICLE 9 BILLING AND PAYMENT 65

9.1 Billing 65

9.2 Payment 66

9.3 Corrections; Disputes 66

9.4 Interest on Past Due Bills 66

9.5 Audit Rights 66

ARTICLE 10 PERFORMANCE SECURITY 67

10.1 Shell Performance Security 67

10.2 Gulf Power Performance Security 68

10.3 Replacement Collateral; Substituted Collateral; Release of Collateral 68

10.4 Draws; Replenishment 69

10.5 Reporting 69

ARTICLE 11 TERM, TERMINATION AND DEFAULTS 69

11.1 Term 69

11.2 Remedies 69

11.3 Termination for Default 69

11.4 Winding Up Arrangements 70

11.5 Shell Defaults 71

11.6 Gulf Power Defaults 72

11.7 Set-off 73

ARTICLE 12 RECORDS; ACCESS TO PLANT AND INFORMATION 73

12.1 Records 73

12.2 Access to Plant 73

12.3 [Intentionally Omitted] 73

12.4 Monthly Operating Reports 73

ARTICLE 13 INDEMNITIES; LIMITATION ON DAMAGES 73

13.1 Indemnity for the Parties’ Personnel and Property 74

13.2 Indemnity for Ownership and Operation of the Plant 74

13.3 Indemnities for Fuel 74

13.4 Indemnity for Energy 74

13.5 SCOPE OF INDEMNITY; WAIVER OF SUBROGATION 74

13.6 Indemnity Procedure 75

13.7 LIMITATION ON DAMAGES 75

13.8 Economic Adjustments 76

ARTICLE 14 FORCE MAJEURE 76

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14.1 Burden of Proof 76

14.2 Suspension of Obligations 76

14.3 Notice of Force Majeure Event 76

ARTICLE 15 CONFIDENTIALITY 77

15.1 Scope 77

15.2 Exceptions 77

15.3 Certain Limitations and Public Announcements. 77

ARTICLE 16 RESOLUTION OF DISAGREEMENTS 78

16.1 Disagreements 78

16.2 Arbitration 78

16.3 No Challenge; Defense of Agreement 79

16.4 Continued Performance 79

16.5 Consolidation 80

ARTICLE 17 ASSIGNMENT 80

17.1 Restriction on Assignment 80

17.2 Exception for Transfers to Affiliates 80

17.3 Exception for Financing 80

ARTICLE 18 REPRESENTATIONS AND WARRANTIES; COVENANTS 80

18.1 Gulf Power’s Representations and Warranties 80

18.2 Shell’s Representations and Warranties 82

18.3 Covenants of Shell 83

18.4 Covenant of Gulf Power 83

18.5 [Intentionally Omitted] 83

18.6 Warranty Disclaimers 83

ARTICLE 19 MISCELLANEOUS PROVISIONS 84

19.1 Entire Agreement 84

19.2 Amendment 84

19.3 Severability 84

19.4 No Waiver 84

19.5 GOVERNING LAW 84

19.6 Preparation of Agreement 84

19.7 Relationship of the Parties 84

19.8 No Third-Party Rights 85

19.9 Notices 85

19.10 Alternate Index 87

19.11 FERC Standard of Review 87

ARTICLE 20 REQUIRED REGULATORY APPROVALS 88

ARTICLE 21 CHANGE OF LAW 89

ARTICLE 22 ACCOUNTING DETERMINATIONS 89

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EXHIBITS

Exhibit 4.1 Capacity Reservation Rate and Variable Energy Rate

Exhibit 4.2 Test Procedures

Exhibit 5.2 Energy Scheduling Procedures and Plant Response Characteristics

Exhibit 5.5 Escalation Factor

Exhibit 5.7 Financial Settlement Calculation

Exhibit 6.2 Fuel Oil Specifications

Exhibit 7.1 Long-Term Preventive Maintenance Program

Exhibit 7.3 Generating Unit Operating Principles

Exhibit 8.3 Calculation of Reference Heat Rates

Exhibit 8.4 Start Charges and Maximum Times for Starts and Shutdowns

Exhibit 8.6 Bonus Availability Factor and Availability Bonus Payments

Exhibit 8.7 Peak Availability Factor and Peak Availability Payments

Exhibit 8.8 Off Peak Availability Factor and Off Peak Availability Payments

Exhibit 10.1 Form of Letter of Credit

Exhibit 10.2 Form of Letter of Guaranty

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POWER PURCHASE AGREEMENT

This Power Purchase Agreement (this “Agreement”) dated March 16, 2009 (the “Effective Date”) is entered into between Shell Energy North America (US), L.P., a Delaware limited partnership (“Shell”), and Gulf Power Company, a Florida corporation (“Gulf Power”).

BACKGROUND STATEMENT

Under the Tenaska ECA (as defined in Section 1.1), Owner owns and operates the Plant (as defined in Section 1.1) and Shell has the exclusive right to the Plant’s generating capacity to convert Fuel (as defined in Section 1.1) to Energy (as defined in Section 1.1) and to receive all Energy capable of being generated by the Plant. Under this Agreement, Gulf Power will pay Shell a fee to reserve all of the generating capacity of the Plant and to have the exclusive right to the Plant’s generating capacity to convert Fuel to Energy and to receive all Energy capable of being generated by the Plant. When Gulf Power desires to convert Fuel to Energy and to receive Energy from Shell, Gulf Power will notify Shell of the timing and amounts of Energy to be generated by the Plant and will cause Fuel to be delivered to the Plant for conversion into Energy and Shell will cause Owner to perform the necessary Energy conversion services. This Agreement sets forth the terms under which Gulf Power will deliver Fuel to Shell and receive Energy generated by the Plant and the payments to be made by Gulf Power as compensation for reserving the Plant’s generating capacity and for the Energy conversion services to be performed as provided herein.

AGREEMENT

Gulf Power and Shell agree as follows:

ARTICLE 1

DEFINED TERMS; INTERPRETATION

1.1 Defined Terms. Unless otherwise required by the context in which a defined term appears, each of the following capitalized terms shall, for all purposes of this Agreement, have the respective meaning set forth below.

“Adjusted Fired Hour Payments” means for a Combustion Turbine for any Contract Year, the amounts, if any, payable by Gulf Power to Shell according to Sections 8.5(d), 8.5(e) and 8.5(f).

“Affiliate” means, when used with reference to a specified Person, any other Person that directly, or indirectly through one or more intermediaries, controls, is controlled by or is under common control with the specified Person. For purposes of the foregoing, “control”, “controlled by” and “under common control with” with respect to any Person means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such

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Person, whether through the ownership of voting securities or partnership interests, by contract or otherwise.

“AGC” means operation of equipment at the Plant necessary to enable a transmission control area operator to adjust the Plant’s output automatically from a control area’s system control center.

“Agreement” has the meaning set forth in the introductory paragraph of this Agreement and includes this Agreement and all exhibits referenced in and attached to this Agreement, as the same may be amended from time to time.

“Alternate Delivery” means delivery of Energy from an Alternate Resource to an Alternate Delivery Point.

“Alternate Delivery Point” means any point on the Transmission System (including interfaces between the Transmission System and other transmission systems) at which Gulf Power is (i) capable of receiving Energy in the quantity to be delivered at such point pursuant to Part III of the Southern OATT as a network resource, and (ii) able to transmit such Energy to its loads without being required to either materially change the output of generating resources available to Gulf Power or materially change the schedule of its preexisting power purchases or sales (other than purchases or sales pursuant to this Agreement) where such schedule change would result in material economic harm to Gulf Power.

“Alternate Resource” means a generating resource (other than the Plant) for which Shell has an unencumbered first call right, which is connected to the Transmission System, either directly or through other transmission systems, and which in Gulf Power’s sole judgment is reasonably reliable to meet Gulf Power’s schedule.

“Ancillary Services” means services ancillary to the operation of a generating facility that can be provided in addition to the sale of Energy or capacity, including voltage/VAR support.

“Applicable Laws” means all laws, ordinances, rules, regulations, orders, interpretations, Permits, judgments, decrees, injunctions, writs and orders of any Governmental Authority or arbitrator that are applicable to either or both of the Parties, the Plant or the terms of this Agreement.

“Arbitration Body” means JAMS/Endispute or, if it no longer exists or no longer handles commercial arbitration matters, the Center for Public Resources or, if it no longer exists or no longer handles commercial arbitration matters, the American Arbitration Association, or such other arbitration body as the Parties may agree.

“Availability Bonus Payments” means the amounts, if any, that Gulf Power is required to pay to Shell according to Section 8.6.

“Availability Payments” means Peak Availability Payments and Off Peak Availability Payments.

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“Availability Tolerance” means, with respect to an hour, the greater of (a) [**] MWhs or (b) [**]% of Base Requested Energy for such hour.

“Barrel” means 42 gallons.

“Base Delivered Energy” means for any hour the least of (a) Delivered Energy for such hour, (b) Requested Energy for such hour, and (c) the Contract Capacity in effect during such hour multiplied by one hour.

“Base Fired Hour Rate” means, for any Month, $[**]/Factored Fired Hour multiplied by the Escalation Factor applicable to such Month.

“Base Requested Energy” means for any hour the lesser of (a) Requested Energy for such hour and (b) the product of (i) the Contract Capacity in effect during such hour minus the sum of (A) the amount of Contract Capacity, if any, for which Shell has elected to make a Cover Payment according to Section 5.7 in respect of such hour, (B) the amount of Contract Capacity, if any, associated with Energy withheld according to Section 5.9 during such hour, and (C) for each Combustion Turbine with respect to which Gulf Power has not requested Power Augmentation in accordance with Section 1 of Exhibit 5.2, the Power Augmentation Capacity of such Combustion Turbine, multiplied by (ii) one hour.

“Bonus Availability Factor” means the Bonus Availability Factor calculated according to Section 1 of Exhibit 8.6.

“Bonus Availability Target” means [**]% for each ContractYear.

“Bonus Hour” means, (i) with respect to the First Contract Year, each of the Peak Hours on each of the 30 Days during the 12-Month period inclusive of both the Pre-Term Period and the First Contract Year for which the average Spark Spread for all Peak Hours of such Day is the highest; and (ii) after the First Contract Year, each of the Peak Hours on each of the 30 Days of such Contract Year for which the average Spark Spread for all Peak Hours of such Day is the highest.

“Btu” means British thermal unit defined as the amount of heat required to raise the temperature of one avoirdupois pound of pure water from fifty-eight and one-half degrees Fahrenheit (58.5°F) to fifty-nine and one-half degrees Fahrenheit (59.5°F) at a constant pressure of fourteen and sixty-five hundredths pounds per square inch absolute (14.65 psia).

“Business Day” means any Day other than a Saturday, a Sunday or a Day on which commercial banks in New York, New York are authorized or required to close.

“Capacity Payments” means the payments Gulf Power is required to make to Shell according to Section 4.1.

“Capacity Reservation Rate” means for each Month during the Operating Term, the amount expressed in $ per Month per MW of Contract Capacity set forth in Exhibit 4.1.

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“Central Prevailing Time” means Central Daylight Savings Time when such time is applicable in Houston, Texas, and otherwise means Central Standard Time.

“Change of Law” has the meaning set forth in Section 21.1.

“Claims” means all claims and actions, whether arising prior to or after the Termination Date, that directly or indirectly relate to the indemnities in this Agreement, and the resulting losses, damages, expenses, attorneys’ fees, experts’ fees and court costs, whether incurred through settlement or otherwise.

“Cold Steam Turbine Start” means a Steam Turbine Start that occurs more than forty-eight (48) hours since the previous Shutdown.

“Combustion Turbine” means each of the combustion turbines included in the definition of “Generating Unit.”

“Communications and Telemetry Equipment” means the equipment, communication channels and related items at the Plant that are necessary to transmit information to Gulf Power’s receiving equipment to enable Gulf Power to monitor the Plant’s operating characteristics on a continuous basis, which consists of all inputs/outputs to/from the Plant’s distributed control system with reasonably acceptable scan rates.

“Confidential” means with respect to a Party’s obligations regarding Confidential Information both during the term of this Agreement and for a period of five years following the Termination Date:

(a)       to keep in safe custody all Confidential Information and not to disclose to any third party any Confidential Information except with the prior written consent of the Party entitled to protection against unauthorized disclosure of Confidential Information; and

(b)       to limit access to Confidential Information to the Party’s officers, directors, employees (and the officers, directors and employees of any other Person that manages the Party) and representatives (including attorneys, accountants and full-time individual consultants) who reasonably require the information in connection with this Agreement, to inform each officer, director, employee and representative of the foregoing restrictions on disclosure of such Confidential Information and to ensure compliance with such restrictions.

“Confidential Information” has the meaning set forth in Section 15.1.

“Contract Capacity” means the capacity of the Plant (expressed in MW) to produce Energy as determined according to Section 4.3, and shall include the Power Augmentation Capacity of each Combustion Turbine.

“Contract Year” means the period of time beginning on the first day of the Operating Term

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and ending on the last day of May, each one-year period thereafter during the Operating Term, and the period beginning on the day after the last such one-year period during the Operating Term and ending on the last day of the Operating Term.

“Costs” has the meaning set forth in Section 11.3.

“Cover Determination” has the meaning set forth in Section 5.7(a).

“Cover Event” has the meaning set forth in Section 5.7(a).

“Cover Order” has the meaning set forth in Section 5.7(a).

“Cover Payment” has the meaning set forth in Section 5.7(g).

“Covered Amount” has the meaning set forth in Section 5.7(a).

“Creditworthy” means a Person has an investment grade rating such that its senior unsecured debt (or issuer rating if such Person has no senior unsecured debt rating) is rated at least BBB by Standard & Poor’s Rating Group and at least Baa2 by Moody’s Investor Services, Inc. and at least BBB by Fitch Ratings where such Person has a senior unsecured debt rating (or issuer rating if such Person has no senior unsecured debt rating) from each of such foregoing rating agencies (the “Rating Agencies”), or from an entity succeeding to the functions and business of such rating agencies. While a Person is not required to have a senior unsecured debt rating (or issuer rating if such Person has no senior unsecured debt rating) from each of the foregoing rating agencies, a Person shall no longer be “Creditworthy” if such Person ceases to have a senior unsecured debt rating (or issuer rating if such Person has no senior unsecured debt rating) from at least one of Standard & Poor’s Rating Group, Moody’s Investor Services, Inc. or Fitch Ratings, or from an entity succeeding to the functions and business of such rating agencies.

“CT Start Rate” means for any Month $[**]/Gulf Power Factored CT Start multiplied by the Escalation Factor applicable to such Month.

“CT Start Reduction” means, for the Contract Year1, (a) [**] for any Contract Year in which there are more than [**] but less than [**] Gulf Power Factored CT Starts, (b) [**]for any Contract Year in which there are more than [**] but less than [**] Gulf Power Factored CT Starts, (c) [**] for any Contract Year in which there are more than [**] but less than [**] Gulf Power Factored CT Starts, (d) [**] for any Contract Year in which there are more than [**] but less than [**] Gulf Power Factored CT Starts, and (e) [**] for any Contract Year in which there are more than [**] but less than [**] Gulf Power Factored CT Starts, it being understood that the CT Start Reduction shall be zero for any Contract Year in which there are less than [**] Gulf Power Factored CT Starts; provided, however, that the First Contract Year shall include any Pre-Term Activities.

_________________________

¹ For purposes of this definition, the First Contract Year shall be deemed to include the Pre-Term Period and the Pre-Term Activities.

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“Cumulative Provisional Peak Availability Amount” has the meaning set forth in Section 8.7(b).

“Cumulative Provisional Off Peak Availability Amount” has the meaning set forth in Section 8.8(b).

“Daily Fuel Oil Price” means a per gallon price for Fuel Oil equal to the [**] or such supply point mutually agreeable to the Parties, plus a commercially reasonable cost-based Fuel Oil transportation and supplier margin adder to be calculated by Gulf Power plus any applicable Taxes and surcharges. The Operating Committee shall establish the procedures and methodology that Gulf Power shall use for determining the Fuel Oil transportation and supplier margin adder.

“Daily Gas Index Price” means for any Gas Day an amount (expressed in $/MMBtu) determined as follows:

Where:
DGIP	=	Daily Gas Index Price for the applicable Gas Day (expressed in $/MMBtu).
A	=	The [**] price [**] for Gas delivered on the applicable Gas Day (expressed in $/MMBtu).
FP	=	The [**] to the Tenaska Gas Delivery Point (expressed as a decimal and calculated in accordance with Transco’s FERC gas tariff, as amended from time to time).
B	=	The [**] to the Tenaska Gas Delivery Point, [**], all as set forth in Transco’s FERC gas tariff as amended from time to time (expressed in $/MMBtu), provided that if a new Transco tariff goes into effect and such new tariff is based upon a type of service (other than firm transportation service) that more closely resembles the way in which Gas is actually delivered to the Plant at the applicable time and Gulf Power actually utilizes such service or a comparable type of service, the Parties will negotiate in good faith to agree upon a revised variable B, it being the Parties’ intent that variable B reflect the way in which Gas is actually delivered to the Plant at the applicable time.

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C = For any Gas Day on which Gas is actually delivered to either or both of the Gas Delivery Points by Gulf Power, the [**] or reimbursable by Gulf Power in respect of such Gas delivered on such Gas Day divided by the quantity of Gas so delivered (expressed in $/MMBtu), or, for any Gas Day on which no Gas is actually delivered to either or both of the Gas Delivery Points by Gulf Power, [**] (expressed in $/MMBtu) that would have been payable by Gulf Power had Gas been delivered at the Tenaska Gas Delivery Point by Gulf Power on such Gas Day.

“Day” means a calendar day beginning at 12:00 midnight, Central Prevailing Time.

“Default” means a default of Shell described in Section 11.5 or a default of Gulf Power described in Section 11.6.

“Defaulting Party” has the meaning set forth in Section 11.2.

“Delivered Energy” means for a period of time the sum of (i) the amount of Energy expressed in MWh generated by the Plant and delivered for the account of Gulf Power at the Energy Point of Delivery during the period, as measured by the Energy Metering Equipment, (ii) Alternate Deliveries, if any, made in accordance with Section 5.7 and (iii) any quantity of Energy for which Shell has made a Financial Settlement in accordance with Section 5.7. For the avoidance of doubt, Energy with respect to which Shell elects to make a Cover Payment shall not be considered to be Delivered Energy for any purpose.

“Delivered Energy Payments” means the payments Gulf Power is required to make to Shell according to Section 5.4.

“Delivered Gas Price” means for any Gas Day an amount (expressed in $/MMBtu) determined as follows:

Where:
DGP	=	Delivered Gas Price for the applicable Gas Day (expressed in $/MMBtu).
A	=	The [**] for Gas delivered on the applicable Gas Day (to the extent this definition applies to Gas scheduled for delivery on the Transco Gas Transporter Facilities) or the [**] for Gas delivered on the applicable Gas Day (to the extent this definition applies to Gas scheduled for delivery on the SONAT Gas Transporter Facilities) (in either case expressed in $/MMBtu).

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FP	=	The applicable [**] or the [**] for the zone extending from the interconnection of the Destin Pipeline and the SONAT Gas Transporter Facilities to the SONAT Gas Delivery Point (to the extent variable A is based upon [**]) (in either case expressed as a decimal and calculated in accordance with the applicable interstate pipeline’s FERC gas tariff, as amended from time to time).
B	=	The actual [**] scheduled for delivery on the applicable Gas Day (a) for [**] or (b) for [**] and the SONAT Gas Transporter Facilities to the SONAT Gas Delivery Point (to the extent variable A is based upon [**] (in either case expressed in $/MMBtu).
C	=	The total of [**] or reimbursable by Gulf Power in respect of Gas delivered to either or both of the Gas Delivery Points on the applicable Gas Day divided by the quantity of Gas so delivered (expressed in $/MMBtu).

“Dollars” and “$” means the lawful currency of the United States of America.

“Duct Fired Energy” means the amount of incremental Delivered Energy generated by operating a heat recovery steam generator with duct firing. The amount of actual Duct Fired Energy shall be determined by dividing the amount of Fuel consumed in the duct burners by an assumed heat rate of [**] MMBtu/MWh.

“Early Termination Date” has the meaning set forth in Section 11.2.

“Effective Date” has the meaning set forth in the introductory paragraph of this Agreement.

“Election Period” has the meaning set forth in Section 5.7(c).

“Electric Index” means for any Day the 16-hour on-peak price index for deliveries into Southern Companies, as published for such Day in Megawatt Daily or, if such index is not published for any Day, the 16-hour on-peak price index for deliveries into the Tennessee Valley Authority, as published for such Day in Megawatt Daily; provided that for any Saturday for which neither such index is published, the Electric Index for such Saturday shall be [**]% of the average of such index as published for the immediately preceding Friday and such index as published for the immediately following Monday.

“Eligible Collateral” means (i) a Letter of Credit, (ii) cash deposited into a Gulf Power Security Account by Shell or a Shell Security Account by Gulf Power, as the case may be, or (iii) a Shell Guaranty or Gulf Power Guaranty, as the case may be.

“Energy” means three phase, 60 hertz, 500,000-volt (nominal) electricity measured in MWh.

“Energy Deficiency Quantity” has the meaning set forth in Section 5.7(f).

“Energy Delivery Tolerance” means, with respect to an hour, the greater of (a) [**] MWhs or (b) [**]% of Requested Energy for such hour.

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“Energy Imbalance Charges” means charges assessed by a Transmission Provider, Transmission Authority or control area services provider for imbalances in the Energy delivered to the Energy Point of Delivery as compared with the amount of Energy scheduled to be delivered at the Energy Point of Delivery.

“Energy Interconnection Agreement” means the agreement between Owner and the Transmission Provider, providing for the operation, and maintenance of Energy Interconnection Facilities necessary for Owner to deliver Energy for the account of Gulf Power according to this Agreement at the Energy Point of Delivery.

“Energy Interconnection Facilities” means the facilities that connect the Generating Units with the transmission system of the Transmission Provider.

“Energy Metering Equipment” means the meters and measuring equipment at the Energy Point of Delivery to measure the capacity of the Plant and Energy delivered by the Plant to the Energy Point of Delivery, as required by the Energy Interconnection Agreement.

“Energy Point of Delivery” means the point at the boundary of or on the Plant Site at which the Generating Units synchronously interconnect with the transmission system of the Transmission Provider, as further described in the Energy Interconnection Agreement.

“Escalation Factor” means for any Month the escalation factor determined according to Exhibit 5.5 for such Month.

“Excess Duct Fired Energy” has the meaning set forth in Section 5.6(c).

“Expected Non-Duct Fired Energy” means (a) the amount of Delivered Energy that the Plant could produce in accordance with the Generating Unit Operating Principles under a given configuration at the applicable ambient conditions without duct firing or Power Augmentation, assuming for this purpose that all equipment (other than Power Augmentation equipment and duct firing equipment) which is required to be operated under the Generating Unit Operating Principles to meet the applicable Request for Energy is operating at design levels except to the extent of any equipment deratings that caused Contract Capacity in the most recent test conducted pursuant to Section 4.3 to be below the level that otherwise would have been achieved, minus (b) a downward adjustment to expected Energy output to account for the maximum expected variances set forth in the Generating Unit Operating Principles.

“Expected Non-Power Augmentation Energy” means (a) the amount of Delivered Energy that the Plant could produce in accordance with the Generating Unit Operating Principles under a given configuration at the applicable ambient conditions with duct firing but without Power Augmentation, assuming for this purpose that all equipment (other than Power Augmentation equipment) which is required to be operated under the Generating Unit Operating Principles to meet the applicable Request for Energy is operating at design levels except to the extent of any equipment deratings that caused Contract Capacity in the most recent test conducted pursuant to Section 4.3 to be below the level that otherwise would have been achieved, minus (b) a downward adjustment to expected

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Energy output to account for the maximum expected variances set forth in the Generating Unit Operating Principles.

“Extended Power Augmentation Energy” means the Power Augmentation Energy produced during (a) the hours in any Day after the time when 48 Power Augmentation Turbine-Hours are accrued on such Day, and (b) the hours in each Day (i) after the time when 288 Power Augmentation Turbine-Hours are accrued subsequent to a Day on which no Power Augmentation Turbine-Hours are incurred and (ii) before the next Day on which no Power Augmentation Turbine-Hours are incurred.

“Extended Power Augmentation Surcharge Rate” means for any Month $[**]/MWh multiplied by the Escalation Factor applicable to such Month.

“Factored Fired Hours” means for each Combustion Turbine for any Month the sum of (a) the total number of Fired Hours for such Combustion Turbine during such Month, (b) 0.3 times the number of Fired Hours of such Combustion Turbine while operating in Power Augmentation mode (excluding periods during which operation in Power Augmentation mode should not have been required, based on the Expected Non-Power Augmentation Energy, to meet the applicable Request for Energy) during such Month, and (c) 0.5 times the number of Fired Hours of such Combustion Turbine while operating on Fuel Oil at Gulf Power’s request during such Month.

“FERC” means the Federal Energy Regulatory Commission or any successor agency.

“Financial Settlement” has the meaning set forth in Section 5.7(h).

“Fired Hour” means with respect to a Combustion Turbine each hour during which such Combustion Turbine is operating and synchronized to the transmission grid for all or part of such hour.

“Fired Hour Payments” means the payments Gulf Power is required to make to Shell according to Section 8.5.

“First Contract Year” shall mean that period of time beginning on the first day of the Operating Term and ending on May 31, 2010.

“Force Majeure” means an act or event that prevents the affected Party in whole or in part from performing its obligations under this Agreement or complying with any conditions required by the other Party under this Agreement if such event is beyond the reasonable control of and not the result of the fault or negligence of the affected Party and such Party has been unable to overcome such event by the exercise of due diligence, including flood, lightning, hurricane, tornado, earthquake, other natural disasters, fire, explosion, epidemic, war, riot, strike or other labor dispute at the Plant, and sabotage. Equipment failure, late delivery of machinery, equipment, materials, spare parts and consumables for the Plant or a delay in the performance of any contractors or suppliers are explicitly excluded from this definition of Force Majeure and are solely the responsibility of the affected Party, except to the extent that such late delivery, failure or delay is within the definition of

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Force Majeure in the preceding sentence. In addition, Force Majeure shall not include economic hardship, changes in market conditions, strikes and labor disputes or weather conditions not included in the first sentence of this definition. The settlement of strikes or other labor disputes at the Plant shall be entirely within the discretion of Owner.

“FPSC” means the Florida Public Service Commission.

“Fuel” means Gas or Fuel Oil, or both.

“Fuel Delivery Points” means, collectively, the Fuel Oil Delivery Point and the Gas Delivery Points.

“Fuel Oil” means No. 2 fuel oil meeting the quality specifications set forth in Exhibit 6.2 and containing no more than 0.05% wt% sulfur and 0.015% wt% fuel bound nitrogen based on test methods referred to in Exhibit 6.2 or such lower levels of sulfur and nitrogen as may be required due to a change in Applicable Laws.

“Fuel Oil Delivery Point” means the receiving flange of the Fuel Oil Unloading Facilities.

“Fuel Oil Storage Facilities” means the Fuel Oil storage tanks on the Plant Site capable of storing at least50,000 Barrels of Fuel Oil.

“Fuel Oil Unloading Facilities” means the facilities and equipment on the Plant Site capable of unloading trucks with loads of 7,000 gallons or more at an average aggregate rate of 30,000 gallons of Fuel Oil per hour.

“Fuel Savings” means for any hour the product (expressed in $/MWh) of the Reference Heat Rate for the Heat Rate Test Date immediately preceding such hour multiplied by the Daily Gas Index Price for the Gas Day in which such hour occurs.

“GAAP” means accounting principles that are generally accepted in the United States.

“Gains” has the meaning set forth in Section 11.3.

“Gas” means natural gas or any mixture of hydrocarbon gases or of hydrocarbon gases and non-combustible gases, consisting predominantly of methane.

“Gas Day” means the 24-hour period commencing at 9:00 a.m. Central Prevailing Time, or such other 24-hour period as may be designated by Gas Daily as the time period for Gas deliveries applicable to the “Daily Price Survey” information used in the definitions of “Daily Gas Index Price” and “Delivered Gas Price.”

“Gas Delivery Point” means either or both of the Tenaska Gas Delivery Point and the SONAT Gas Delivery Point.

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“Gas Receipt Facilities” means (a) with respect to Gas delivered at the Tenaska Gas Delivery Point, the Tenaska Gas Receipt Facilities and (b) with respect to Gas delivered at the SONAT Gas Delivery Point, the SONAT Gas Receipt Facilities.

“Generating Unit” means (a) an “F” Class combustion turbine, with a nominal design net electric generating capacity of approximately160 MW per turbine generator at an ambient temperature of99°F dry bulb and 76°F wet bulb or an approximately400 MW steam turbine and (b) an electric generator associated with such turbine.

“Generating Unit Operating Principles” means the principles set forth in Exhibit 7.3, the Plant response characteristics set forth in Exhibit 5.2 and the Start and Shutdown parameters set forth in Exhibit 8.4.

“Governmental Authority” means any federal, state, local, municipal or other governmental, administrative, judicial or regulatory entity having or asserting jurisdiction over a Party, Owner, the Plant or this Agreement.

“Gulf Power” has the meaning set forth in the introductory paragraph of this Agreement and includes Gulf Power’s successors and permitted assigns.

“Gulf Power Factored CT Starts” means the number of Gulf Power Factored CT Starts calculated according to Exhibit 8.4.

“Gulf Power Guarantor” means a Person that, at the time of execution and delivery of its Gulf Power Guaranty, is a direct or indirect owner of Gulf Power and (a) is Creditworthy with a consolidated Net Worth of at least [**]; or (b) is reasonably acceptable to Shell as having verifiable credit worthiness and Net Worth sufficient to secure Gulf Power’s Guarantor’s obligations under its Gulf Power Guaranty.

“Gulf Power Guaranty” means a guarantee provided by a Gulf Power Guarantor in the form attached hereto as Exhibit 10.2.

“Gulf Power Security Account” means an account designated by Gulf Power for the benefit of Gulf Power, under the exclusive control of Gulf Power free and clear of all liens (including the liens of any lenders) of any person or entity other than Gulf Power. Any Gulf Power Security Account shall be established and maintained at the expense of Shell and held by a depositary bank acceptable to Gulf Power pursuant to a control agreement in form and substance acceptable to Gulf Power.

“Heat Rate Payments” means the payments, if any, Shell is required to make to Gulf Power according to Section 8.3(f) and the payments, if any, Gulf Power is required to make to Shell according to Section 8.3(e).

“Heat Rate Test” means a test of the Plant’s heat rate conducted on Gas according to the procedures set forth in Exhibit 4.2 sequentially with a test of the Plant’s capacity under Section 4.3.

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“Heat Rate Test Date” has the meaning set forth in Section 8.3(a).

“Hot Steam Turbine Start” means a Steam Turbine Start that occurs eight (8) hours or less since the previous Shutdown.

“Inadvertent Energy” means Energy generated by the Plant in any hour in excess of the sum of the Requested Energy for such hour plus the Energy Delivery Tolerance for such hour.

“Indebtedness” of any Person means all of the following without duplication: (a) obligations of such Person for borrowed money evidenced by bonds, debentures, notes, loan agreements or other similar instruments; (b) purchase money indebtedness of such Person constituting an obligation to pay the deferred purchase price of property or services, other than trade payables incurred in the ordinary course of business; (c) lease obligations of such Person which are capitalized on the balance sheet of such person in accordance with GAAP; (d) liabilities of such Person with respect to letters of credit or applications or reimbursement agreements therefore; and (e) net obligations of such Person under any swap or hedging agreement.

“Interim Off Peak Request Factor” means (a) [**] hours for each of the Months of May and September, (b) [**]hours for each of the Months of June, July and August, (c) [**] hours for each of the Months of December, January and February, and (d) [**] hours for each of the Months of October, November, March and April.

“Interim Off Peak Request Shortfall” has the meaning set forth in Section 8.8(b).

“Interim Off Peak Target Request Quantity” means, as of the end of any Month, the sum of the products of the following for each Month of the applicable Contract Year through such Month: (a) the Interim Off Peak Request Factor for such Month, multiplied by (b) the Contract Capacity during such Month.

“Interim Peak Request Factor” means (a) [**] hours for each of the periods of May 15 through May 31 and September 1 through September 15, (b) [**]hours for each of the Months of June, July and August, and (c) [**] hours for each of the Months of December, January and February.

“Interim Peak Request Shortfall” has the meaning set forth in Section 8.7(b).

“Interim Peak Target Request Quantity” means, as of the end of any Month, the sum of the products of the following for each Month of the applicable Contract Year through such Month: (a) the Interim Peak Request Factor for such Month, multiplied by (b) the Contract Capacity during such Month.

“kWh” means kilowatt-hour.

“Letter of Credit” means a standby letter of credit in the form attached hereto as Exhibit 10.1

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which is issued by a U.S. commercial bank or a U.S. branch of a foreign bank with total assets of at least $[**] having a general long-term senior unsecured debt rating of A minus or higher (as rated by Standard & Poor’s Rating Group and Fitch Ratings) and A3 or higher (as rated by Moody’s Investor Services, Inc.), or a comparable rating by an entity succeeding to the functions and business of such rating agencies; and (ii) permits presentation at banks located in Atlanta, Georgia (if provided on behalf of Shell) and Houston, Texas (if provided on behalf of Gulf Power).

“Losses” has the meaning set forth in Section 11.3.

“Lowest Credit Rating” means the lowest currently maintained senior unsecured credit rating (or issuer rating where such Person has no senior unsecured rating) by Standard and Poor’s Rating Group, Moody’s Investor Services Inc., or Fitch Ratings, or any entity succeeding the business and function thereof, where such Person has a senior unsecured or issuer rating.

“Material Adverse Change” means, as to Gulf Power, that Gulf Power or, if Gulf Power is providing Eligible Collateral in the form of a Gulf Power Guaranty, the Gulf Power Guarantor, experiences any of the events described in clauses (a) or (b), and as to Shell, that Shell or, if Shell is providing Eligible Collateral in the form of a Shell Guaranty, that the Shell Guarantor experiences any of the events described in clauses (a) or (b): (a) the Shell Guarantor or Gulf Power Guarantor is not Creditworthy or the Shell Guarantor or Gulf Power Guarantor is not Creditworthy and experiences a further deterioration in its credit rating by a Rating Agency; or (b) the maturity of any Indebtedness of such Person which in the aggregate exceeds ten percent (10%) of Net Worth, is accelerated by the holder or holders thereof as a result of default by (x) Gulf Power or Gulf Power’s Guarantor or (y) Shell or Shell’s Guarantor, as the case may be.

“Metal Products Index” means the Producer Price Index-Commodities (WPU1076), Not Seasonally Adjusted (Group: Metals and metal products; Item: Fabricated steel plate), as determined and reported by the Bureau of Labor Statistics.

“Minimum Adjusted Fired Hour Charge” means $[**] multiplied by the Escalation Factor applicable to the calendar year in which such Contract Year begins, provided that for any Contract Year after the First Contract Year that consists of less than 365 Days, the amount so determined shall be multiplied by a fraction, the numerator of which is the number of days in such Contract Year and the denominator of which is 365.

“Minimum Duration” has the meaning set forth in Section 5.7(a).

“Minimum Load” means with respect to a Generating Unit the level of output specified as Minimum Load in Exhibit 7.3.

“Minimum Pressure” means a pressure sufficient to allow Gas delivered at a Gas Delivery Point to be transported through the applicable Gas Receipt Facilities and to enter the Combustion Turbine(s) assuming that the applicable Gas Receipt Facilities and Combustion Turbine(s) are in good condition and proper working order and are being operated according to good industry practices and Prudent Generator Practices.

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“MMBtu” means million Btu.

“Month” means a calendar month.

“Monthly Provisional Off Peak Availability Payment” has the meaning set forth in Section 8.8(c).

“Monthly Provisional Off Peak Availability Refund” has the meaning set forth in Section 8.8(d).

“Monthly Provisional Peak Availability Payment” has the meaning set forth in Section 8.7(c).

“Monthly Provisional Peak Availability Refund” has the meaning set forth in Section 8.7(d).

“MW” means megawatt.

“MWh” means megawatt-hour.

“NERC” means the North American Electric Reliability Council or any successor entity.

“NERC-Determined Capacity” has the meaning set forth in Section 4.1(c).

“Net Worth” means the dollar value calculated by subtracting liabilities from total assets (excluding goodwill and other intangible assets described in FASB Statement 142) as such terms are determined in accordance with GAAP.

“Non-Conforming Request for Energy” has the meaning set forth in Section 7.3.

“Non-Defaulting Party” has the meaning set forth in Section 11.2.

“NYMEX Gas Contracts” means Henry Hub gas futures contracts traded on the New York Mercantile Exchange.

“Off Peak Availability Factor” means for any Contract Year, the Off Peak Availability Factor calculated according to Section 1 of Exhibit 8.8.

“Off Peak Availability Measurement Period” means for any Contract Year all hours during such Contract Year that are not within the Peak Availability Measurement Period.

“Off Peak Availability Payments” means the amounts, if any, Shell is required to pay to Gulf Power according to Section 8.8, including all Monthly Provisional Off Peak Availability Payments, if any, made by Shell to Gulf Power minus all Monthly Provisional Off Peak Availability Refunds, if any, made by Gulf Power to Shell.

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“Off Peak Availability Target” means [**]% for the Off Peak Availability Measurement Period of any Contract Year, provided that such percentage shall be reduced by subtracting the Start Reduction for the applicable Contract Year.

“Off Peak Hours” means the hours during each Day that are not Peak Hours.

“Off Peak Period” means the period from [**] inclusive and the period from [**]inclusive each Contract Year.

“Oil-Generated Energy” means for a period of time the number of MWhs of Delivered Energy (excluding a pro-rata portion of any Inadvertent Energy) that are produced by a Combustion Turbine (but excluding any associated MWhs of Delivered Energy that are produced by the Steam Turbine) while the Combustion Turbine is fired on Fuel Oil at the direction of Gulf Power.

“Oil-Generated Energy Surcharge Payments” means the payments Gulf Power is required to make to Shell according to Section 5.5.

“Oil-Generated Energy Surcharge Rate” means for any Month [**]/MWh multiplied by the Escalation Factor applicable to such Month.

“Operating Project Documents” means this Agreement, the Operations and Maintenance Agreement, the Energy Interconnection Agreement, the Transco Gas Interconnect Agreement and the SONAT Gas Interconnect Agreement.

“Operating Committee” means the committee established pursuant to Section 7.5.

“Operating Procedures” means those procedures developed by the Parties pursuant to Section 7.4(b).

“Operating Representatives” means those individuals appointed by each of the Parties to the Operating Committee pursuant to Section 7.5.

“Operating Term” means the period of time beginning on the later of (a) June 1, 2009 or (b) the first day of the Month following the earlier of (i) issuance of a final order, without conditions or qualifications, by the FPSC; (ii) the date of acceptance by Gulf Power in accordance with Section 20.2; (iii) the date upon which all rights of termination by either Party pursuant to Section 20.2 have expired, or (iv) such earlier date as the Parties may mutually agree and ending on the Termination Date.

“Operations and Maintenance Agreement” means the agreement between Owner and the Operations and Maintenance Contractor.

“Operations and Maintenance Contractor” means the entity engaged by Owner to operate and maintain the Plant and any successor entity.

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“Outage” means any outage of the Plant that fully or partially curtails the Plant’s ability to deliver Energy.

“Owner” means Tenaska Alabama II Partners, L.P. in its capacity as owner of the Plant, and any successor thereto.

“Parties” means Gulf Power and Shell.

“Party” means either Gulf Power or Shell.

“Payment Adjustment Factor” means the factor calculated according to Section 4.1(c)(i).

“Peak Availability Factor” means the Peak Availability Factor calculated according to Section 1 of Exhibit 8.7.

“Peak Availability Measurement Period” means for any Contract Year all of the Peak Hours from Monday through [**] (excluding Days recognized as holidays by NERC) during the Peak Period of such Contract Year. For avoidance of doubt, the Peak Availability Measurement Period shall becalculated without regard to any Force Majeure event.

“Peak Availability Payments” means the amounts, if any, Shell is required to pay to Gulf Power according to Section 8.7, including all Monthly Provisional Peak Availability Payments, if any, made by Shell to Gulf Power minus all Monthly Provisional Peak Availability Refunds, if any, made by Gulf Power to Shell.

“Peak Availability Target” means [**]% for the Peak Availability Measurement Period of each Contract Year, provided that such percentage shall be reduced by subtracting the Start Reduction for the applicable Contract Year.

“Peak Hours” means the 16 consecutive hours during each Day designated as the Peak Hours by Gulf Power no later than 2:00 p.m. on the Day before the first Day covered by the designation. In the absence of such designation, the Peak Hours shall be from the hour ending at 7:00 a.m. through the hour ending at 10:00 p.m. Central Prevailing Time.

“Peak Period” means the period from [**] inclusive and the period from [**] inclusive each Contract Year.

“Permit” means any license, permit, authorization, waiver, exemption, variance, franchise or similar order of or from any Governmental Authority.

“Permitted Scheduled Outage Capability” means the expected Plant Capability during a Permitted Scheduled Outage, as set forth in the final Scheduled Outage schedule established according to Section 7.1.

“Permitted Scheduled Outage Completion Date” has the meaning set forth in Section 7.1(b).

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“Permitted Scheduled Outages” has the meaning set forth in Section 7.1(b).

“Person” means an individual, corporation, limited liability company, voluntary association, joint stock company, business trust, partnership, agency or other entity.

“Pipeline Measurement Facilities” means the Gas metering and measurement facilities of (a) Transco located at the Tenaska Gas Delivery Point and (b) SONAT located at the SONAT Gas Delivery Point.

“Plant” means the approximately 880 MW combined cycle power plant owned and operated by Owner in Autauga County, Alabama, including land, all Energy producing equipment and its auxiliary equipment, plant control systems, Gas Receipt Facilities (to the extent owned or leased by Owner), Fuel Oil Storage Facilities, Fuel Oil Unloading Facilities, a switchyard, Energy Interconnection Facilities (to the extent owned or leased by Owner) necessary to deliver Energy to the Transmission Provider, and plant buildings.

“Plant Capability” means the maximum sustained output the Plant is capable of generating at the then current ambient conditions consistent with Prudent Generator Practices when operating on the Fuel designated by Gulf Power.

“Plant Site” means the parcel or parcels of land on which the Plant is located.

“Power Augmentation” means the generation of incremental Energy from one or more of the Combustion Turbines through the injection of steam from the Steam Turbine or the heat recovery steam generators into the combustor(s) of such Combustion Turbine(s).

“Power Augmentation Capacity” means the capacity of each Combustion Turbine (expressed in MW) to produce Energy from Power Augmentation as determined according to Sections 4.2 and 4.3.

“Power Augmentation Energy” means, for a period of time during which a Combustion Turbine produces Energy through the use of Power Augmentation (excluding periods during which operation in Power Augmentation mode should not have been required, based on the Expected Non-Power Augmentation Energy, to meet the applicable Request for Energy), the number of MWh equal to the product of (a) the Power Augmentation Capacity of such Combustion Turbine (expressed in MW) multiplied by (b) the length of such period (expressed in hours).

“Power Augmentation Lead Time” has the meaning set forth in Exhibit 5.2.

“Power Augmentation Surcharge Payments” means the payments Gulf Power is required to make to Shell according to Section 5.6(a).

“Power Augmentation Turbine-Hour” means each hour that a Combustion Turbine is operated in Power Augmentation mode (excluding periods during which operation in Power

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Augmentation mode should not have been required, based on the Expected Non-Power Augmentation Energy, to meet the applicable Request for Energy), it being the intent that an hour during which all three Combustion Turbines are operated in Power Augmentation mode (excluding periods during which operation in Power Augmentation mode should not have been required, based on the Expected Non-Power Augmentation Energy, to meet the applicable Request for Energy) will count as three Power Augmentation Turbine-Hours.

“Pre-Term Activities” means Shell’s activities associated with the Plant during the Pre-Term Period all calculated in accordance with the definitions and procedures as described in this Agreement.

“Pre-Term Period” means that period from June 1, 2009 through the day immediately preceding the first day of the Operating Term.

“Prevailing Party” has the meaning set forth in Section 16.2(i).

“Prudent Generator Practices” means any of the practices, methods and acts engaged in or approved by a significant portion of the independent power industry in the United States during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in the light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at the lowest reasonable cost consistent with good business practices, reliability, safety and expedition. Prudent Generator Practices is not intended to be limited to the optimum practice, method or act to the exclusion of all others, but rather to be acceptable practices, methods and acts generally accepted in the United States, having due regard for, among other things, manufacturers’ warranties, contractual obligations, the requirements or guidance of Governmental Authorities, Applicable Laws, applicable SERC operating guidelines and rules, independent system operator rules, NERC policies, the requirements of insurers and the requirements of the Operating Project Documents.

“Reference Heat Rate” has the meaning set forth in Section 8.3(a).

“Related Parties” of a Person means its corporate Affiliates, parent, subsidiaries, equity owners, Affiliates of its equity owners, owners of its equity owners and their directors, officers, stockholders, employees and agents.

“Request for Energy” means a request by Gulf Power according to this Agreement for Delivered Energy which request may be modified through AGC.

“Requested Energy” means for a period of time the amount of Energy expressed in MWh requested by Gulf Power in a Request for Energy, as further described in Sections 5.2 and 7.3.

“Responsible Party” means the party responsible for gas pipeline imbalance charges according to Sections 6.1(k) and 6.1(l).

“Scheduled Outage” means a planned Outage to perform maintenance according to

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manufacturers’ recommendations and Prudent Generator Practices.

“Scope” of a Scheduled Outage has the meaning set forth in Section 7.1(b).

“SERC” means the Southeast Electric Reliability Council, or similar or successor organization.

“Shell” has the meaning set forth in the introductory paragraph of this Agreement and includes Shell’s successors and permitted assigns.

“Shell CTPA” has the meaning set forth in Section 5.6(b).

“Shell Guarantor” means a Person that, at the time of execution and delivery of its Shell Guaranty, is a direct or indirect owner of Shell and (a) is Creditworthy with a consolidated Net Worth of at least [**]; or (b) is reasonably acceptable to Gulf Power as having a verifiable creditworthiness and Net Worth sufficient to secure Shell Guarantor’s obligations under its Shell Guaranty.

“Shell Guaranty” means a guaranty provided by the Shell Guarantor in the form attached hereto as Exhibit 10.2.

“Shell Performance Security” has the meaning set forth in Section 10.1.

“Shell Security Account” means an account designated by Shell for the benefit of Shell, under the exclusive control of Shell free and clear of all liens (including the liens of any lenders) of any person or entity other than Shell. Any Shell Security Account shall be established and maintained at the expense of Gulf Power and held by a depositary bank acceptable to Shell pursuant to a control agreement in form and substance acceptable to Shell.

“Shutdown” means the reduction of output of a Generating Unit from Minimum Load to zero in response to a Request for Energy or as a result of Gulf Power’s failure to provide Fuel meeting the requirements of Section 6.1(c) or Gulf Power’s failure to arrange and cause to be provided transmission services to support transmission of the Requested Energy from the Energy Point of Delivery.

“SONAT” means Southern Natural Gas Company and its successors and permitted assigns under the SONAT Gas Interconnect Agreement.

“SONAT Gas Interconnect Agreement” means the gas interconnect agreement between Owner and SONAT titled: Construction and Reimbursement of Measuring Station Agreement-Tenaska Alabama II Meter Station and providing for the interconnection of SONAT’s mainline with the SONAT Gas Receipt Facilities.

“SONAT Gas Delivery Point” means the point of interconnection between the SONAT Gas Transporter Facilities and the SONAT Gas Receipt Facilities located approximately ten miles from

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the boundary of the Plant Site.

“SONAT Gas Receipt Facilities” means the facilities on the downstream side of the SONAT Gas Delivery Point, including the Gas pipeline and associated facilities.

“SONAT Gas Transport Facilities” means the Gas pipeline and other Gas transportation facilities of SONAT, including the facilities that interconnect with the SONAT Gas Receipt Facilities at the SONAT Gas Delivery Point, as further described in the SONAT Gas Interconnect Agreement.

“Southern Control Area” means the electric system of the Southern Companies that has been recognized by NERC and SERC as a control area.

“Spark Spread” has the meaning set forth in Section 2 of Exhibit 8.7.

“Standard Power Augmentation Energy” means Power Augmentation Energy that is not Extended Power Augmentation Energy.

“Standard Power Augmentation Surcharge Rate” means for any Month $[**]/MWh multiplied by the Escalation Factor applicable to such Month.

“Start” means the commencement of operation up to the requested output of a Generating Unit in response to a Request for Energy or as a result of a manual start of a Combustion Turbine to respond to an AGC signal during a period in which Gulf Power has directed that the Plant operate in AGC mode.

“Start Charge” means the amounts payable by Gulf Power to Shell for Steam Turbine Starts according to Section 8.4(c).

“Start Ratio” has the meaning set forth in Section 8.5(b).

“Start Reduction” means for any Contract Year the greater of the CT Start Reduction for such Contract Year and the ST Start Reduction for such Contract Year.

“Statement” means a billing statement delivered by Shell or Gulf Power according to Section 9.1.

“Steam Turbine” means the steam turbine included in the definition of “Generating Unit.”

“ST Examination” has the meaning set forth in Section 7.1(d).

“ST Interim Maintenance” has the meaning set forth in Section 7.1(d).

“ST Scheduled Maintenance” has the meaning set forth in Section 7.1(d).

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“ST Start Reduction” means, for any Contract Year2, (a) zero, for any Contract Year in which there are [**] or fewer Cold Steam Turbine Starts and Warm Steam Turbine Starts, and (b) the product of [**] multiplied by the quotient of (i) the number of Cold Steam Turbine Starts and Warm Steam Turbine Starts for the applicable Contract Year minus [**] (ii) divided by [**], for any Contract Year in which there are more than [**]Cold Steam Turbine Starts and Warm Steam Turbine Starts; plus for any Contract Year, an additional [**] reduction as shown in the following table, based on the total of Cold Steam Turbine Starts plus those Warm Steam Turbine Starts occurring greater than thirteen (13) hours since Shutdown:

Total Cold/Warm (>13 hrs) ST Starts	Reduction(*)
[**]	[**]
[**]	[**]
[**]	[**]
[**]	[**]
[**]	[**]
[**]	[**]
[**]	[**]
[**]	[**]
[**]	[**]
[**]	[**]

^(*) The percentage reduction for a Contract Year will be determined through linear interpolation if the total of Cold Steam Turbine Starts plus Warm Steam Turbines Starts occurring greater than thirteen (13) hours since Shutdown falls between values in the above table.

“Taxes” means any and all ad valorem, property, occupation, severance, production, extraction, first use, conservation, Btu or energy, gathering, transport, pipeline, utility, gross receipts, municipal usage or easement, gas or oil revenue, gas or oil import, privilege, sales, use, consumption, excise, lease, transaction, and other or new taxes, governmental charges, licenses, fees, permits, and assessments, or increases therein, other than taxes based on net income or net worth.

“Tenaska ECA” means the Energy Conversion Agreement between Owner and Shell dated July 14, 2000 including all exhibits and any amendments or modifications thereto.

“Tenaska Gas Delivery Point” means the point of interconnection between the Transco Gas Transporter Facilities and the Tenaska Gas Receipt Facilities located approximately 1.7 miles from the boundary of the Plant Site.

“Tenaska Gas Receipt Facilities” means the facilities on the downstream side of the Tenaska Gas Delivery Point, including the Gas pipeline and associated facilities.

“Termination Date” means the earlier to occur of (a) May 24, 2023 and (b) the Day on which termination of this Agreement becomes effective as provided herein.

_________________________

² For purposes of this definition, the First Contract Year shall be deemed to include the Pre-Term Period and the Pre-Term Activities.

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“Termination Payment” has the meaning set forth in Section 11.3.

“Tested Heat Rate” means the Plant’s heat rate as determined by the Heat Rate Test conducted for such Contract Year, provided that the Plant’s heat rate for the First Contract Year shall be determined by Shell in accordance with the procedures as set forth in this Agreement and promptly communicated to Gulf Power.

“TG Index” means the Producer Price Index Revision-Current Series (PCU3511#), Not Seasonally Adjusted (Industry: Turbines and turbine generator sets; Product: Turbines and turbine generator sets), as determined and reported by the Bureau of Labor Statistics.

“Tier 1 Adjustment Rate” means for any Month$[**]/Factored Fired Hour multiplied by the Escalation Factor applicable to such Month.

“Tier 1 Fired Hour Rate” means for any Month$[**]/Factored Fired Hour multiplied by the Escalation Factor applicable to such Month.

“Tier 2 Adjustment Rate” means for any Month $[**]/Factored Fired Hour multiplied by the Escalation Factor applicable to such Month.

“Tier 2 Fired Hour Rate” means for any Month$[**]/Factored Fired Hour multiplied by the Escalation Factor applicable to such Month.

“Transco” means Transcontinental Gas Pipe Line Corporation and its successors and permitted assigns under the Transco Gas Interconnect Agreement.

“Transco Gas Interconnect Agreement” means the gas interconnect agreement between Owner and Transco providing for the interconnection of Transco’s mainline with Tenaska Gas Receipt Facilities.

“Transco Gas Transporter Facilities” means the Gas pipeline and other Gas transportation facilities of Transco, including the facilities that interconnect with the Tenaska Gas Receipt Facilities at the Tenaska Gas Delivery Point, as further described in the Transco Gas Interconnect Agreement.

“Transmission Authority” means an independent system operator, regional transmission organization or similar entity, if any, with jurisdiction over electrical transmission in the region in which the Plant is located.

“Transmission Outage” means a Scheduled Outage required to be performed during the Peak Period as a result of the order of a Transmission Authority or Transmission Provider, to the extent that failure to schedule a Scheduled Outage during the Peak Period would (a) result in a fine or penalty being payable by Shell or Owner or (b) cause the Scheduled Outage to be deferred beyond the time that it is required to be performed according to Prudent Generator Practices.

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“Transmission Provider” means Alabama Power Company or any successor thereto that provides electric transmission services at the Energy Point of Delivery.

“Transmission System” means the integrated high voltage electricity transmission systems of the electric utility operating companies of the Southern Company (currently Alabama Power Company, Georgia Power Company, Gulf Power Company and Mississippi Power Company), as modified or expanded from time-to-time, as well as any successor in function thereto, and includes the Georgia Integrated Transmission System.

“Unpermitted Scheduled Outage” has the meaning set forth in Section 7.1(b).

“Unscheduled Outage” means an Outage caused by any circumstance, including a Force Majeure event, but excluding a Scheduled Outage.

“Variable Energy Rate” means the amount expressed in $ per MWh set forth in the column with the heading “Variable Energy Rate” opposite to such Month in Exhibit 4.1.

"Variable Interest" has the meaning as defined in applicable GAAP.

“Variable Maintenance Rate” means for any Month $[**]/MWh multiplied by the Escalation Factor applicable to such Month.

“Warm Steam Turbine Start” means a Steam Turbine Start that occurs more than eight (8) hours, but not more than forty-eight (48) hours, since the previous Shutdown.

“Withholding Payment” has the meaning set forth in Section 5.9.

1.2 Interpretation. In this Agreement:

(a) The headings are for convenience only and shall be ignored in construing this Agreement.

(b) Where the context requires, the singular includes the plural and vice versa.

(c) The words “include,” “includes” and “including” shall be deemed to be followed by the words “without limitation.”

(d) Unless the context otherwise indicates, references in this Agreement to articles, sections or exhibits are references, respectively, to articles, sections or exhibits of or to this Agreement.

(e) All exhibits referenced in this Agreement are incorporated into this Agreement by such reference and are an integral part of this Agreement. If a conflict or inconsistency exists between the exhibits and this Agreement (exclusive of the exhibits) the provisions of this Agreement (exclusive of the exhibits) shall control. If any conflict exists among the exhibits, the exhibit dealing with the matter in more detail shall control.

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(f)  All references in this Agreement to heat rate or heat content shall be deemed to be in higher heating value (HHV).

(g) All references in this Agreement to contracts and agreements shall be deemed to refer to such contracts and agreements as amended, modified and supplemented from time to time, unless otherwise expressly provided.

(h) The words “hereof,” “herein,” “hereto” and “hereunder” and words of similar import shall, unless otherwise expressly specified, refer to this Agreement as a whole and not to any particular portion or provision of this Agreement.

ARTICLE 2

[NOT USED]

ARTICLE 3

PLANT FACILITIES AND EQUIPMENT

3.1 The Plant. Shell shall cause the Plant to be operated and maintained, and shall perform all of its obligations under this Agreement, in accordance with Prudent Generator Practices.

3.2 Energy Metering Equipment. Shell shall cause the Energy Metering Equipment to be operated and maintained to measure capacity of the Plant and Energy delivered to Gulf Power at the Point of Delivery. Gulf Power shall have the right to inspect, test and read the Energy Metering Equipment. Shell shall cause the Energy Metering Equipment to be inspected and tested at least once every Contract Year and at any other time upon the reasonable request of Gulf Power. Gulf Power shall pay the costs of tests of the Energy Metering Equipment requested by Gulf Power if Gulf Power requests more than one test during a Contract Year, unless the results of any such test show the Energy Metering Equipment to be inaccurate by more than one-half of one percent, in which case Shell shall pay the costs of such test. If the Energy Metering Equipment is found by Shell or Gulf Power to be inaccurate, Shell shall, pursuant to the Energy Interconnection Agreement (or other interconnection arrangements) promptly arrange for the calibration, repair or replacement of the Energy Metering Equipment. If the Energy Metering Equipment is found by Shell or Gulf Power to be inaccurate by more than one percent, an adjustment shall be made correcting all measurements made by the inaccurate portion of the Energy Metering Equipment for:

(a) The actual period during which inaccurate measurements were made, if such period can be determined; or, if not,

(b) The period immediately preceding the test of the Energy Metering Equipment equal to one-half the time from the date of the last previous test of the Energy Metering Equipment, provided that the period covered by any such correction shall not exceed six Months.

Shell shall give Gulf Power reasonable advance notice of Energy Metering Equipment tests, and Gulf Power has the right to observe the tests and to conduct its own tests to verify Shell’s procedures and results.

3.3 Communications and Telemetry Equipment. Shell shall cause the Communications and

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Telemetry Equipment at the Plant to be programmed, operated and maintained.

ARTICLE 4

CAPACITY PAYMENTS; CAPACITY TESTS

4.1 Capacity Payments. (a) Gulf Power shall make Capacity Payments to Shell for each Month during the Operating Term. The Capacity Payment for a particular Month shall equal the Contract Capacity applicable to such Month multiplied by the Capacity Reservation Rate applicable to such Month.

(b)      For any partial Month occurring at the beginning or end of the Operating Term, the Capacity Payment shall be determined by multiplying an amount determined according to Section 4.1(a) for such Month by a fraction, the numerator of which is the number of Days of the Month within the Operating Term and the denominator of which is the number of Days in the Month.

(c)      If at any time during the Operating Term for more than 30 consecutive Days NERC or other applicable regulatory body determines the capacity of the Plant (for reasons other than a Permitted Scheduled Outage, contractual commitments to sell capacity or for other reasons caused by Gulf Power) to be less than [**] MW for purposes of capacity sales (the “NERC-Determined Capacity”) and the Plant Capability is, in fact, less than [**] MW, the Capacity Payments shall be adjusted during the period beginning at the end of such 30-Day period and ending when the greater of NERC-Determined Capacity or Plant Capability is [**] MW or more, as follows:

(i)        while the greater of Plant Capability or NERC-Determined Capacity is less than [**] MW but greater than or equal to [**]MW, the Capacity Payment shall be the Capacity Payment determined according to Sections 4.1(a) and 4.1(b) multiplied by the Payment Adjustment Factor calculated as follows:

PAF = 0.65 – [([**] – CC) x 0.001]

Where:

PAF = Payment Adjustment Factor;

CC =              The number of MWs of the greater of (i) NERC-Determined Capacity or (ii) Plant Capability at the applicable time;

(ii)       while the NERC-Determined Capacity and Plant Capability are less than [**] MW, the Capacity Payment shall be zero.

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For purposes of the foregoing calculation, there shall be added to both NERC-Determined Capacity and Plant Capability for any period of time an amount equal to (i) the Covered Amount, if any, for which Shell is making Cover Payments with respect to such period of time according to Section 5.7 (ii) the Alternate Deliveries, if any, made during for such period in accordance with Section 5.7 and (iii) the quantity of Energy that is the subject of a Financial Settlement for such period, in each case divided by the number of hours in such period. Gulf Power shall notify Shell promptly upon receiving notice that NERC or any such regulatory body is considering making such a determination or has made such a determination, and shall reasonably cooperate with Shell in seeking to avoid or reverse any such determination.

(d)      If the Energy Interconnection Agreement is terminated or canceled, unless such termination or cancellation was caused by Gulf Power, and, by the end of the initial 200-Day cure period set forth in Section 11.5(i), if the Energy Interconnection Agreement is not reinstated on the same terms and Shell has not caused Owner to put in place an interconnection agreement or other arrangements for interconnection reasonably acceptable to Gulf Power with respect to the Transmission Provider, the Capacity Payment shall be zero until the time when the Energy Interconnection Agreement is reinstated on the same terms or such reasonably acceptable agreements or arrangements are in place with respect to the Transmission Provider; for purposes of this Section 4.1(d), a replacement interconnection agreement or arrangement will be considered to be acceptable to Gulf Power if such agreement or arrangement is no less favorable to Gulf Power and Owner (to the extent the rights and obligations of Owner thereunder could reasonably be expected to affect Gulf Power and/or its ability to receive capacity, Energy and Ancillary Services from the Plant) than the interconnection agreements or arrangements that are generally available to electric generators in the region at the relevant time.

4.2 Initial Contract Capacity. For the First Contract Year, the Contract Capacity and the Power Augmentation Capacity, respectively, shall be determined by Shell utilizing the procedures as set forth in this Agreement and promptly communicated to Gulf Power.

4.3 Annual Test to Set Contract Capacity. (a) For each Contract Year following the First Contract Year, Shell shall, by notice to Gulf Power, set the Contract Capacity based on an annual summer capability test conducted by Owner between March 1 and June 30 immediately prior to the beginning of the applicable Contract Year. Each such capability test shall be conducted sequentially with the Heat Rate Test required under Section 8.3(b) for the applicable Contract Year. The Contract Capacity shall be set by Shell at the lowest of the following: (i) [**] MW, (ii) the net capacity of the Plant as determined by the applicable summer capability test conducted by Owner according to Exhibit 4.2, and (iii) a level selected by Shell that is not less than (x) the net capacity of the Plant as determined by the applicable summer capability test minus (y) 20 MW. The summer capability test used to set Contract Capacity for each Contract Year shall include a test of the Power Augmentation Capacity performed according to Exhibit 4.2. For each Contract Year following the First Contract Year, Shell shall, by notice to Gulf Power, set the Power Augmentation Capacity for each Combustion Turbine (each of which shall be equal) at the lower of the following: (i) [**] MW, and (ii) a level selected by Shell that is not less than (x) one-third of the total portion of the net capacity of the Plant attributable to Power Augmentation as determined according to Exhibit 4.2 minus (y) two MW. The Contract Capacity and Power Augmentation Capacity set by Shell for the immediately succeeding Contract Year shall take effect on the first day of such immediately

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succeeding Contract Year. If final test results are not available by the first day of the immediately succeeding Contract Year, the Contract Capacity and Power Augmentation Capacity for such succeeding Contract Year will be based on the preliminary report of test results provided according to Exhibit 4.2 until the results of the annual summer capability test are available and used to set the Contract Capacity and Power Augmentation Capacity for the applicable Contract Year. When the final test results are available, the Parties shall make an adjustment of Capacity Payments (and any other calculations under this Agreement incorporating Contract Capacity or Power Augmentation Capacity) from the beginning of the applicable Contract Year to reflect the Contract Capacity and Power Augmentation Capacity based on the final test results. If a capability test for a Contract Year is conducted after the beginning of such Contract Year, the Contract Capacity and Power Augmentation Capacity set for such Contract Year pursuant to this Section 4.3(a) nevertheless shall apply from the first day of such Contract Year; provided, however, to the extent necessary for any payments or calculations using Contract Capacity and Power Augmentation Capacity for such Contract Year prior to the preliminary report of test results, the Parties on an interim basis shall use the Contract Capacity and Power Augmentation Capacity for the prior Contract Year until such preliminary report of test results is available and then shall make adjustments of such payments and calculations in accordance with the preliminary report of test results and final test results as provided above.

(b)      If the output of the Plant is adversely affected at the time a capacity test under Section 4.3(a) is scheduled to take place or during such a test by an equipment failure or malfunction or failure of Gulf Power to provide Fuel, Shell has the right to (and, upon Gulf Power’s request, shall) cause Owner to reschedule the test (and the associated Heat Rate Test) as soon as possible after such failure or malfunction has been remedied. Until the results of the rescheduled test are available, Capacity Payments (and any other calculations under this Agreement incorporating Contract Capacity) will be based upon the lesser of (i) the Contract Capacity in effect immediately before the scheduled time for the test, and (ii) the Plant Capability when burning Gas and when adjusted to the rating conditions set forth in Table 2-1 of Exhibit 4.2. When the results of the rescheduled test are available, the Parties shall make an adjustment of Capacity Payments (and any other calculations under this Agreement incorporating Contract Capacity or Power Augmentation Capacity) to reflect the Contract Capacity and Power Augmentation Capacity set pursuant to the rescheduled test, which adjustment shall be effective from the beginning of the applicable Contract Year.

4.4 Right to Observe Tests. Upon receiving notice from Owner as to the dates and times that Owner has scheduled tests to set Contract Capacity and Power Augmentation Capacity, Shell shall promptly notify Gulf Power of same, and Gulf Power shall have the right to observe such tests.

4.5 Additional Tests. Owner may conduct additional capacity tests as required by SERC or as required to obtain or maintain environmental Permits or testing of equipment necessary to comply with equipment warranties, but such additional tests shall not be used to set or adjust Contract Capacity or Power Augmentation Capacity. Shell shall give Gulf Power reasonable advance notice of, and Gulf Power shall have the right to observe, such additional tests.

4.6 Test Fuel and Delivered Energy. (a) [Intentionally Omitted]

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(b)      For all tests and preventive maintenance activities that take place during the Operating Term, Gulf Power shall cause Fuel to be delivered to the Fuel Delivery Points and shall cause Energy to be accepted at the EnergyPoint of Delivery sufficient to allow performance of the tests referred to in Sections 4.3 and 4.5 and performance of preventive maintenance activities. Shellshall notify Gulf Power of Shell’s good faith nomination of the quantity of Gas required in connection with any such tests no later than 8:10 a.m. by telephone Central Prevailing Time on the Day before the Day of delivery and then by electronic communication system as soon as prudentlypossible. Energy delivered to the Energy Point of Delivery during such tests and activities will be treated as Delivered Energy in an amount equal to a Request for Energy and paid for by Gulf Power. Shell may use Fuel Oil in the Fuel Oil Storage Facilities to the extent needed to conduct preventive maintenance activities.  Shell shall notify Gulf Power of the quantity of any Fuel Oil so used.  If Gulf Power’s retail native load incremental cost less ten percent (10%) is below the cost of production of such tests and activities, [**].  Gulf Power’s production cost for such test or preventive maintenance activity energy shall equal the Delivered Energy Payments, the Oil-Generated Energy Surcharge Payments and the Power Augmentation Surcharge Payments for such Energy, plus the Fired Hour Payments attributable to such Energy, plus a fuel cost component determined based on the Delivered Gas Price for the Day on which such Gas was delivered (in the case of Gas) or Gulf Power’s cost (in the case of Fuel Oil) and the actual Fuel consumption during the test or preventive maintenance activity. Shell shall give Gulf Power notice of any such test and activities (including the amounts of Fuel to be used and Energy to be produced) at least 24 hours before Owner commences any test or preventive maintenance activity under this Section 4.6(b).  The test energy shall be non-firm andneither party shall have any right to assess penalties or to seek damages associated with the failure of Shell to deliver or Southern to receive energy from test or maintenance activities.

ARTICLE 5

ENERGY PURCHASES AND PAYMENTS

5.1 Energy Purchases. (a) Subject to the terms and conditions of this Agreement, Gulf Power has the sole and exclusive right during the Operating Term, but has no obligation, to direct the conversion of Fuel into Energy by the Plant at any level up to the Plant Capability and to receive or cause to be received all Energy produced by the Plant, except to the extent provided in Section 5.8. Shell shall cause Owner to provide Energy conversion services as set forth in Gulf Power’s Requests for Energy.

(b)      Gulf Power shall have and retain title to all Energy generated by the Plant from and after the time it is produced, both before and after delivery of the Energy to the Energy Point of Delivery. Notwithstanding the preceding sentence, as between the Parties, Shell shall be deemed to be in exclusive control and possession of the Energy produced under this Agreement, and responsible for any damage or injury caused thereby, prior to the time the Energy is delivered at the Energy Point of Delivery. After delivery of Energy to the Energy Point of Delivery, as between the Parties, Gulf Power shall be deemed to be in exclusive control and possession of the Energy and responsible for any injury or damage caused thereby.

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5.2 Requests for Energy. Each Request for Energy by Gulf Power shall be made according to the procedures set forth in Exhibit 5.2. The generation schedule in each Request for Energy shall continue in force unless and until Gulf Power communicates a modification of the schedule in the Request for Energy. Any such modification shall provide sufficient notice to allow the Plant to respond to the modification within the response characteristics set forth in Exhibit 5.2. Gulf Power shall receive or cause to be received all Energy produced by the Plant during any Start or Shutdown. Gulf Power shall assume full responsibility and risk for arranging and providing for transmission of Delivered Energy from the Energy Point of Delivery. Shell shall not incur any reduction in the Peak Availability Factor or the Off Peak Availability Factor due to failure to deliver Delivered Energy that result from curtailment, suspension, interruption or reduction of transmission, as a result of the direction of the Transmission Provider, an independent system operator, a regional transmission operator or other Person with responsibility for operation or control of the Energy Interconnection Facilities or the transmission facilities that are interconnected with the Energy Interconnection Facilities at the Energy Point of Delivery, unless such curtailment, suspension, interruption or reduction results from Shell’s failure to cause the Plant to be operated and maintained in accordance with the Energy Interconnection Agreement, this Agreement or Prudent Generator Practices. In documenting and confirming Requests for Energy under this Agreement, conversations between the Parties’ respective personnel may be tape recorded and any such recording shall satisfy any “writing” requirements under Applicable Law.

5.3 Ancillary Services. Shell shall, subject to any requirements of the Transmission Provider or independent system operator under the Energy Interconnection Agreement, cause Owner to provide Ancillary Services requested by Gulf Power to the extent Owner is able to do so (a) in compliance with Applicable Laws, Prudent Generator Practices and the Generating Unit Operating Principles and (b) without impairing the Plant’s ability to meet a Request for Energy. Gulf Power shall reimburse Shell for reasonable additional documented costs incurred by Shell (or for which Shell is responsible) in providing Ancillary Services requested by Gulf Power. If the Plant is used to provide Ancillary Services to the Transmission Provider or independent system operator, Shell shall pay to Gulf Power all compensation payable by Owner to Shell in respect of such Ancillary Services. The preceding sentence shall not limit the provisions of Section 5.8.

5.4 Delivered Energy Payments. Gulf Power shall, for each Month during the Operating Term, pay Shell for conversion of Fuel into Energy an amount equal to the number of MWhs of Delivered Energy (excluding any Inadvertent Energy) for such Month multiplied by the Variable Energy Rate applicable to such Month. With respect to Delivered Energy provided in the form of Alternate Deliveries, the Delivered Energy Payment shall also include any Fuel Savings calculated in accordance with Section 5.7(j).

5.5 Oil-Generated Energy Surcharge Payments. In addition to the payments contemplated by Sections 5.4 and 5.6(a), Gulf Power shall for each Month during the Operating Term, pay Shell for Oil-Generated Energy in an amount equal to the number of MWhs of Oil-Generated Energy, if any, for such Month multiplied by the Oil-Generated Energy Surcharge Rate applicable to such Month.

5.6 Power Augmentation Surcharge Payments; Reimbursement for Fuel Usage. (a) In addition to the payments contemplated by Sections 5.4 and 5.5, Gulf Power shall for each Month

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during the Operating Term, pay to Shell (i) for Standard Power Augmentation Energy an amount equal to the number of MWhs of Standard Power Augmentation Energy, if any, for such Month multiplied by the Standard Power Augmentation Surcharge Rate applicable to such Month, and (ii) for Extended Power Augmentation Energy an amount equal to the number of MWhs of Extended Power Augmentation Energy, if any, for such Month multiplied by the Extended Power Augmentation Surcharge Rate applicable to such Month.

(b)      For each hour (or portion thereof) during which a Combustion Turbine is operated in Power Augmentation mode when such operating mode should not have been required, based on the Expected Non-Power Augmentation Energy, to meet the applicable Request for Energy (a “Shell CTPA”), Shell shall pay to Gulf Power an amount equal to the product of (i) the Daily Gas Index Price for the Gas Day in which the applicable hour occurs, multiplied by (ii) [**] MMBtu/MWh, multiplied by (iii) the Power Augmentation Capacity, multiplied by (iv) one hour (or the applicable portion thereof).

(c)      For each hour (or portion thereof) during which a heat recovery steam generator with duct firing is operated when such operating mode should not have been required, based on the Expected Non-Duct Fired Energy, to meet the applicable Request for Energy, Shell shall pay to Gulf Power an amount equal to the product of (i) the Daily Gas Index Price for the Gas Day in which the applicable hour occurs, multiplied by (ii) [**] MMBtu/MWh minus the Tested Heat Rate as determined for the Heat Rate Test Date immediately preceding the applicable time of operation, multiplied by (iii) any Excess Duct Fired Energy for such hour (or the applicable portion thereof). “Excess Duct Fired Energy” means, for any hour, the amount by which (i) Duct Fired Energy exceeds (ii) the amount of Duct Fired Energy that would have been required to meet the applicable Request for Energy based on the Expected Non-Duct Fired Energy.

5.7 Cover Options. (a) If, at any time during the Operating Term, an Unscheduled Outage renders the Plant unable to fulfill, in whole or in part, any current or future Requests for Energy received from Gulf Power (“Cover Event”), Shell shall, as soon as it becomes aware thereof, provide notice of such Cover Event to Gulf Power. As soon as reasonably practicable after such initial notice, Shell shall provide to Gulf Power an additional notice (the “Cover Order”) setting forth, on the basis of the best information then available and consistent with Prudent Generator Practices, the reason for the Cover Event, the portion of the Contract Capacity impaired by the Cover Event, the number of megawatts of impaired Contract Capacity for which Shell wishes to obtain a determination of the Cover Payment (the “Covered Amount”), and Shell’s good faith estimates of the minimum duration (“Minimum Duration”) and the most likely duration thereof. As soon as reasonably practicable but in any event by 12:00 p.m. Central Prevailing Time on the next Business Day after Gulf Power’s receipt of the Cover Order, Gulf Power shall provide to Shell notice setting forth Gulf Power’s determination, as of the time of such notice, of the Cover Payment (to be determined as set forth below) that would be applicable with respect to each whole or partial Month included in the Cover Order (the “Cover Determination”), provided that partial Months may be included in a Cover Order only in the case of Months occurring at the beginning or end of the Minimum Duration. As Shell obtains additional information from Owner concerning such Cover Event, Shell shall provide to Gulf Power prompt notice of Owner’s updated good faith estimate of the Minimum Duration and the expected duration thereof. Gulf Power shall provide to Shell prompt

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notice refreshing Gulf Power’s Cover Determination applicable with respect to the Cover Order, based upon the update of the Minimum Duration of the Cover Event set forth in Shell’s Cover Order (but excluding any impaired Contract Capacity that is then the subject of an effective Election Period). Shell’s notice obligations under this Section 5.7(a) shall apply in all circumstances without regard to whether Shell wishes to obtain a Cover Determination or wishes to make a Cover Payment.

(b)      If the impaired Contract Capacity resulting from a Cover Event exceeds 150 MW, Shell may issue separate Cover Orders with respect to portions of the impaired Contract Capacity, provided that if Shell issues more than one Cover Order for the same period to the extent possible each Cover Order shall be issued with respect to a Covered Amount increment of an integral multiple of 50 MW of capacity. If Shell issues separate Cover Orders in these circumstances, each Cover Order will be treated separately for all purposes of this Section 5.7.

(c)      At the time of receipt of the Cover Determination, Shell shall either (i) accept the Cover Determination by irrevocably committing to pay to Gulf Power the Cover Payment calculated as of the time of such election based on the Covered Amount specified in the Cover Order, in which case Requests for Energy will be considered Non-Conforming Requests for Energy according to Section 7.3 to the extent they would require operation of the Plant using the portion of the Contract Capacity included in the Covered Amount for the period during which such Covered Amount is the subject of an effective Election Period with respect to which Shell makes the required Cover Payment, or (ii) decline to pay a Cover Payment, in which case Requests for Energy will not be considered Non-Conforming Requests for Energy (except to the extent expressly provided in Section 7.3) and any shortfall of Base Delivered Energy below Base Requested Energy shall reduce the Bonus Availability Factor according to Exhibit 8.6 and/or the Peak Availability Factor according to Exhibit 8.7 and/or the Off Peak Availability Factor according to Exhibit 8.8 for the duration of the Cover Event or until the subsequent election of an Election Period. A Cover Determination may be accepted in its entirety or in increments of whole Months or of partial Months beginning or ending at the beginning or end of the Minimum Duration and any such whole or partial Month for which Shell accepts a Cover Determination is referred to as an “Election Period.” Unless and until Shell elects to pay a Cover Payment with respect to a Cover Event pursuant to this Section 5.7(c), any shortfall of Base Delivered Energy below Base Requested Energy shall reduce the Bonus Availability Factor according to Exhibit 8.6 and/or the Peak Availability Factor according to Exhibit 8.7 and/or the Off Peak Availability Factor according to Exhibit 8.8 for the duration of the Cover Event. Gulf Power shall use reasonable commercial efforts to minimize the amount of any Cover Determination pursuant to Section 5.7(a). Any election by Shell pursuant to this Section 5.7(c) to accept a Cover Determination must be made immediately in response to receipt of such Cover Determination and in any event must be made at least 30 minutes prior to the day session close of trading on the New York Mercantile Exchange of NYMEX Gas Contracts on the Day of the election. If Shell does not accept a Cover Determination for the full Covered Amount or the full period of such Cover Determination, it may issue an updated Cover Order and Gulf Power shall issue an updated Cover Determination according to Section 5.7(a) up to twice per week, and Shell may accept or decline such updated Cover Determination according to the provisions of this Section 5.7(c).

(d)      During an Election Period, Shell shall not be obligated to receive Gas from or deliver Energy to Gulf Power hereunder to the extent prevented from doing so by the relevant Cover Event. If a Cover Event ends before the end of a corresponding Election Period, beginning at the

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time the Cover Event ends, Gulf Power shall have the right to issue Requests for Energy in respect of the capacity affected by the Cover Event. A Cover Payment or portion of Cover Payment applicable to each Day in an Election Period shall be paid by Shell to Gulf Power at the same time as other amounts set forth on the Statement covering such Day are payable according to Section 9.2, it being understood that Shell may accept a Cover Determination only for whole Months and, to the extent permitted by Section 5.7(c), for partial Months at the beginning or end of the Minimum Duration.

(e)      If, at any time and from time to time, after Shell elects to pay a Cover Payment with respect to an Election Period, Shell determines, in good faith and consistent with Prudent Generator Practices, that the actual duration of the applicable Cover Event is highly likely to be longer than the Minimum Duration set forth in Shell’s Cover Order for the then-current Election Periods, Shell shall provide to Gulf Power prompt notice of such determination, and Gulf Power shall provide to Shell prompt notice (by 12:00 p.m. Central Prevailing Time on the next Business Day) setting forth Gulf Power’s determination of the Cover Payment that would be applicable to the additional estimated minimum duration of such Cover Event. At any time prior to the expiration of the ongoing Election Period relating to any Cover Order, Shell shall have the option to elect pursuant to Section 5.7(c) to pay a Cover Payment in respect of such Cover Order as determined by Gulf Power, notified by Gulf Power to Shell and elected by Shell with respect to such additional minimum duration. The failure of Shell to notify Gulf Power of such election prior to the expiration of the ongoing Election Period shall constitute an election by Shell not to pay a Cover Payment with respect to the impaired Contract Capacity included in the applicable Cover Order for the additional duration of the Cover Event. If Shell elects to pay a Cover Payment with respect to the impaired Contract Capacity included in the applicable Cover Order for all or a portion of the additional estimated minimum duration of the relevant Cover Event, the additional time period for which Shell elects to pay a Cover Payment shall constitute a separate Election Period. If Shell determines that the actual duration of a Cover Event as to which Shell has elected to pay a Cover Payment will be shorter than the Minimum Duration or estimated additional minimum duration set forth in Shell’s election pursuant to Section 5.7(c) or this Section 5.7(e), Shell shall also provide to Gulf Power prompt notice of such determination, but any ongoing Election Period will not be shortened without Gulf Power’s consent.

(f)      The “Energy Deficiency Quantity” for the Election Period applicable to such Cover Order shall be equal to the portion of the impaired Contract Capacity specified as a Covered Amount in such Cover Order times the number of hours in the Election Period.

(g)      For purposes of this Agreement, the term “Cover Payment” shall mean an amount (but not less than zero) determined by the following formula:

[A x (B – (C x D) – E + F)] + G + H

Where:
A	means the Energy Deficiency Quantity for an Election Period (expressed in MWh);

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B	means, in the case of a quantity of Energy based on an increment of capacity in an integral multiple of 50 MW, the lowest of the offer prices quoted to Gulf Power by three non-Affiliate third parties in the broker market with respect to an arm’s-length purchase by Gulf Power of a quantity of Energy equal to the Energy Deficiency Quantity in SERC or, in the case of a quantity of Energy based on an increment of capacity of other than an integral multiple of 50 MW, a price determined by Gulf Power in good faith (expressed in Dollars per MWh);
C	means the Reference Heat Rate for the Heat Rate Test Date occurring most recently before the time of calculation;
D	means: (i) for all partial Months of an Election Period, the highest forward bid price for a balance-of-the-Month Daily Gas Index Price swap, quoted by three non-Affiliate third parties in the broker market; or (ii) for all whole Months of an Election Period, at Shell’s election, either (1) a fixed price quoted by Gulf Power, or (2) the settlement price for NYMEX Gas Contracts on the date of the Cover Determination with respect to such Cover Event (or, if no such settlement prices are quoted on such date, the first Day thereafter on which such settlement prices are quoted) for Energy for delivery in each such Month during such Election Period, adjusted using basis differentials (determined based upon quotes received from three non-Affiliate parties in the broker market) to reflect a price equivalent to the Daily Gas Index Price (in any case expressed in Dollars per MMBtu);
E	means the Variable Energy Rate applicable to the Election Period; plus the Fired Hour Payments, Oil-Generated Energy Surcharge Payments and Power Augmentation Surcharge Payments that Gulf Power reasonably determines it would have incurred during the Election Period (expressed in Dollars per MWh);
F	means the aggregate incremental (expressed as a positive amount) or decremental (expressed as a negative amount) transmission costs, if any, that would be incurred or realized by Gulf Power in connection with its purchase of Energy to replace the Energy Deficiency Quantity (expressed in Dollars per MWh);
G	means the total positive option premium(s) quoted by three non-Affiliate third parties in the broker market for an “out of the money” put option for the Energy Deficiency Quantity during the Election Period allowing Gulf Power to sell the Energy Deficiency Quantity at a price determined on a strike whose formula is [(C x D) + E] (expressed in Dollars); and

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H means all good faith costs incurred by Gulf Power as the result of the replacement of Ancillary Services from the Plant that otherwise would have been provided under this Agreement but for the occurrence of the relevant Cover Event and, during Months in which the provisions of Section 4.1(c) apply, all good faith costs incurred by Gulf Power as the result of replacement of capacity from the Plant that otherwise would have been available but for the occurrence of the relevant Cover Event to the extent such capacity is necessary to firm the deliveries of Energy included within the Cover Order (all expressed in Dollars).

(h)      During the pendency of any Cover Event, beginning with the first hour of such Cover Event (or the first hour following any Election Period and ending on the thirtieth day thereafter, Shell shall have the option to elect the following financial settlement procedure (“Financial Settlement”). In the event that Shell exercises the Financial Settlement option, for each hour during which Gulf Power makes a Request for Energy that would cause a shortfall between Delivered Energy and Requested Energy, (i) Shell shall pay alternate liquidated damages based on the formulas included in Exhibit 5.7 and (ii) the quantity of Delivered Energy for such hour shall equal Requested Energy. To exercise the Financial Settlement option, Shell must provide Gulf Power with advance telephonic notice (to be promptly followed by written confirmation) by 10:00 a.m. Central Prevailing Time of the second Day of the Cover Event. Any shortfall of Base Delivered Energy below Base Requested Energy before Shell exercises such option (to the extent not the subject of an election to make a Cover Payment) shall reduce the Bonus Availability Factor according to Exhibit 8.6 and/or the Peak Availability Factor according to Exhibit 8.7 and/or the Off Peak Availability Factor according to Exhibit 8.8 for the duration of the Cover Event.

(i)       If Shell has elected the Financial Settlement option, Shell shall have the further option to elect to substitute physical Alternate Delivery from an Alternate Resource at an Alternate Delivery Point (all in accordance with the further provisions of this Section 5.7) for the entire remaining portion of the Cover Event, provided that such further election may only be made upon advance telephonic notice to Gulf Power given prior to 3:00 p.m. Central Prevailing Time of the Day that is two Business Days prior to the date when such Alternate Delivery will begin, which notice must be promptly followed by written confirmation. Upon exercise of the Alternate Delivery election, Shell’s rights to the Financial Settlement option will terminate beginning on the date that such Alternate Delivery is scheduled to begin pursuant to Shell’s notice, and Shell shall not be entitled to reinstate such Financial Settlement option for the duration of the Cover Event. Shell’s election of the Alternate Delivery option shall likewise terminate any election to make Cover Payment to the extent notified by Shell in making such election. Shell may change the Alternate Resource from time to time, provided that Shell provides Gulf Power with advance telephonic notice (to be promptly followed by written confirmation) no later than 3:00 p.m. Central Prevailing Time of the Day that is two Business Days prior to the date when such change in Alternate Resource is to occur, which notice shall specify the Alternate Resource that Shell intends to utilize. If Shell elects to provide Energy from an Alternate Resource, it shall provide Gulf Power with a uniform quantity of Energy in each hour that Gulf Power schedules at least that quantity of Energy.

(j)       The Energy delivered from an Alternate Resource shall constitute Delivered Energy for all purposes under this Agreement and the Delivered Energy Payment shall be increased, for each MWh of Delivered Energy that is provided from an Alternate Resource pursuant in an amount equal to the Fuel Savings associated with such MWh of Delivered Energy.

(k) Gulf Power may deduct from the Delivered Energy Payment the amount of the

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incremental additional costs incurred by Gulf Power due to system losses as a result of Shell’s delivery of Energy from an Alternate Resource, as compared to the losses that Gulf Power would have incurred if such Energy were delivered from the Plant. Gulf Power shall determine the amount of incremental additional Energy losses in a manner consistent with the methodology utilized by Gulf Power in applying loss penalties in its system dispatch; provided, however, such methodology shall not treat Shell’s Alternate Resource in a materially different manner from Gulf Power’s other generating resources. In the event the incremental additional losses are determined to be less than two percent (2%) of Gulf Power’s Request for Energy in any Day for which such losses are calculated, there shall be no deduction for losses.

5.8 Exclusivity. Notwithstanding anything to the contrary, throughout the Operating Term, Shell shall cause Owner not to provide or sell to any Person, other than Gulf Power, any capacity, Energy or Ancillary Services made available or produced by the Plant, except that notwithstanding this Section 5.8 or any other provision of this Agreement, Shell or Owner, as applicable, may (a) provide Ancillary Services to the Transmission Provider, independent system operator or regional transmission operator as may be required under the Energy Interconnection Agreement, Applicable Law or applicable self-regulatory scheme and (b) sell any Energy withheld according to the provisions of Section 5.9; provided that at any time when Gulf Power is in default under Section 11.6 (after giving effect to any cure period) and if Shell has provided to Gulf Power at least four days’ written notice of its intention to exercise its rights under this Section 5.8 Shell may enter into (and then perform) agreements with terms of up to one year to sell capacity and/or Energy and/or Ancillary Services to other parties, and with net revenue from such sales credited against amounts payable by Gulf Power to Shell under this Agreement, provided that (i) if Gulf Power holds any transmission rights directly associated with the Plant that are needed by Shell to sell Energy to third parties, Gulf Power shall (a) undesignate the Plant as a network resource and (b) assign any such rights to Shell at Shell’s option and upon Shell’s request, to the maximum extent permitted by Applicable Laws and by third party agreements and shall in any case refrain from designating or using such rights in any manner that would interfere with Shell’s ability to sell Energy to third parties, and (ii) Gulf Power’s obligations under this Agreement shall not be diminished in any respect.

5.9 Shell’s Option to Withhold a Limited Amount of Energy. Shell has the right to elect not to provide during any Off Peak Hour an amount of Energy not exceeding one-fourth of the Contract Capacity applicable during such hour multiplied by one hour by giving four Business Days’ prior notice of the election to Gulf Power. Such notice shall specify (a) the number of MWh of Energy that Shell elects to not provide during each such Off Peak Hour (subject to the limitation in the preceding sentence), and (b) the Off Peak Hours during which such Energy will not be provided. If Shell makes the election described in this Section 5.9, Shell shall pay to Gulf Power, for each hour during which Shell does not provide Energy under this Section 5.9, an amount (the “Withholding Payment”) calculated as follows:

Where:

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WP	=	Withholding Payment applicable to an Off Peak Hour (expressed in Dollars).
Q	=	The quantity of Energy not provided under this Section 5.9 in such Off Peak Hour (expressed in MWh).
EI	=	The Electric Index applicable to the Day in which such Off Peak Hour occurs (expressed in $/MWh).
VM	=	The Variable Maintenance Rate for the Month in which such Off Peak Hour occurs (expressed in $/MWh).
FS	=	Fuel Savings for such Off Peak Hour (expressed in $/MWh).

5.10     Pre-Term Activities. Shell shall provide Gulf Power with such information as Gulf Power may reasonably request to confirm Shell’s activities and interaction with the Plant during the Pre-Term Period.

ARTICLE 6

FUEL SUPPLIES AND DELIVERIES

6.1 Gas Deliveries. (a) During each hour of each Day during the Operating Term, except to the extent the Plant is not operating due to an Outage, Gulf Power shall have the right but not the obligation to deliver Gas at either or both of the Gas Delivery Points (as selected by Gulf Power) in such quantities as, in accordance with the terms of this Agreement, may be required to meet Gulf Power’s Requests for Energy of up to 100% of the Plant Capability. Shell shall use commercially reasonable efforts to cause Owner, Transco and SONAT to designate Gulf Power as the respective agent for the delivery point operator at each of the Gas Delivery Points. To the extent Gulf Power wishes to deliver Gas under this Section 6.1(a), Gulf Power shall be responsible for obtaining and paying for any transportation necessary for the delivery of Gas to the applicable Gas Delivery Point(s). Shell shall cause Owner to receive and accept such Gas at the applicable Gas Delivery Point(s) and convert such Gas to Energy as provided in Sections 5.2, 7.2 and 7.3 according to the applicable Request for Energy. To the extent the Plant is unable to operate due to an Outage, Owner shall not be required to receive Gas and convert it to Energy, but the Outage shall be treated according to the applicable provisions of this Agreement regarding availability. This Section 6.1(a) shall not relieve Gulf Power of its obligations under Section 4.6.

(b)      As between the Parties, Gulf Power shall be deemed to be in exclusive control and possession of the Gas delivered under this Agreement, and responsible for any damage or injury

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caused thereby, prior to the time the Gas is delivered at the applicable Gas Delivery Point. After delivery of Gas to the applicable Gas Delivery Point, as between the Parties, Shell shall be deemed to be in exclusive control and possession of the Gas and responsible for any injury or damage caused thereby. Notwithstanding the preceding two sentences, title to all Gas delivered under this Agreement shall remain with Gulf Power and shall not pass from Gulf Power to Shell or Owner.

(c)      The quality of all Gas delivered under this Agreement shall conform to the pipeline specifications of Transco (for Gas delivered at the Tenaska Gas Delivery Point) or SONAT (for Gas delivered at the SONAT Gas Delivery Point), in each case as in effect from time to time, and the Gas shall be at a pressure of no less than the applicable Minimum Pressure. During any period of time when Gas fails to meet such quality specifications or Minimum Pressure, Owner may either accept the non-conforming Gas or refuse to accept the Gas. If Owner refuses to accept delivery of non-conforming Gas, Gulf Power shall be deemed to have failed to deliver such Gas for purposes of Section 7.3. If Owner accepts delivery of non-conforming Gas, Gulf Power shall have no liability with respect to the non-conforming Gas.

(d)      The measurement of Gas delivered under this Agreement, including determining pressure, heating value, temperature and specific gravity, and calibration and correction of metering equipment, shall comply with the applicable specifications of the Transco pipeline system at the Tenaska Gas Delivery Point (for Gas delivered at the Tenaska Gas Delivery Point) or the applicable specifications of the SONAT pipeline system at the SONAT Gas Delivery Point (for Gas delivered at the SONAT Gas Delivery Point). The quantities of Gas consumed on each Day for purposes of determining the Heat Rate Payment under Section 8.3 shall be based on the quantities of Gas delivered to the Plant as measured by the applicable Pipeline Measurement Facilities. To the extent that the measurement specifications of Transco’s pipeline system or SONAT’s pipeline system, as applicable, provide for the adjustment of measurements to correct for inaccurate Pipeline Measurement Facilities, the resulting adjusted measurements shall be incorporated into such Gas consumption calculations. In such a case, if a Heat Rate Payment has already been made based on incorrect measurements, the Heat Rate Payment shall be recalculated based on the adjusted measurements, and any necessary Heat Rate Payment adjustment shall be included on the next succeeding Statement. Gulf Power shall give reasonable notice to Shell so that Shell may have a representative present to observe any cleaning, changing, repairing, inspecting, testing, calibrating or adjusting of the Pipeline Measurement Facilities. Shell shall have the right, but not more often than semi-annually, to request that Gulf Power exercise its rights under the applicable Gas transportation agreement to inspect and calibrate, or cause to be inspected and calibrated, the Pipeline Measurement Facilities. The costs of any such inspection and calibration shall be borne by Gulf Power, except that Shell shall reimburse Gulf Power for such costs if (i) the inspection does not reveal a measurement error outside of the permitted tolerances under the applicable Gas transportation agreement and (ii) Gulf Power is required to reimburse the Gas transporter for such costs under the terms of the applicable Gas transportation agreement. The official charts (recordings) from the Pipeline Measurement Facilities which are made available to Gulf Power under the applicable Gas transportation agreement shall remain the property of Gulf Power or its designee. Upon request by Shell, Gulf Power shall exercise its rights under the applicable Gas transportation agreement to obtain metering statements, records and charts, together with calculations therefrom, reflecting measurements and readings of the Pipeline Measurement Facilities, and shall submit the statements, records, charts and calculations so obtained to Shell for inspection and verification, subject to return

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to Gulf Power or its designee within ten Days after Shell’s receipt thereof.

(e)      Gulf Power shall bear the costs of maintaining and testing the Pipeline Measurement Facilities at the Tenaska Gas Delivery Point, except as otherwise provided in Section 6.1(d). Gulf Power will reimburse Shell for any costs described in this Section 6.1(e) that are incurred by Shell (or for which Shell is responsible) within ten Business Days following receipt by Gulf Power of an invoice therefore, accompanied by appropriate supporting documentation. In the event of any overpayment by Gulf Power, Shell shall refund the amount of such overpayment to Gulf Power within ten Business Days after such funds are payable to Shell from Owner. Shell shall use commercially reasonable efforts to minimize the costs to be borne by Gulf Power under this Section 6.1(e). Upon request by Gulf Power, Shell shall use reasonably commercial efforts to cause Owner to request from SONAT and/or Transco to permit Gulf Power to install, at Gulf Power’s sole cost and risk, electronic gas check measurement equipment at either or both of the Gas Delivery Points and Gulf Power shall be solely responsible for any and all charges and incremental costs associated with the purchase, installation, maintenance and use of such equipment. Such check metering equipment will not replace the Pipeline Measuring Facilities. Should SONAT and/or Transco grant this request, Gulf Power shall provide Shell with electronic measurement signals from each such check meter. Shell shall reimburse Gulf Power for any and all additional costs associated with providing the measurement signals from the check meters.

(f)      As between the Parties, Shell shall at its cost and risk cause Owner to operate and maintain the Tenaska Gas Receipt Facilities on the Plant side of the Tenaska Gas Delivery Point and the SONAT Gas Receipt Facilities on the Plant side of the SONAT Gas Delivery Point, in each case as necessary for the receipt of Gas at the Plant. Without limiting the foregoing, as between the Parties, Shell shall be responsible for the prompt detection and repair of any leaks and other problems downstream of the Gas Delivery Points, and shall promptly investigate and remedy any problem identified by Gulf Power. Shell shall reimburse Gulf Power (at the Delivered Gas Price) for any losses of Gas occurring downstream of the applicable Gas Delivery Point.

(g)      The agent for the point operator shall notify Transco and SONAT from time to time whether the Tenaska Gas Receipt Facilities or the SONAT Gas Receipt Facilities, as applicable, are on pressure or flow control operation, based upon Gulf Power’s designations to Shell from time to time.

(h)      Gulf Power shall designate a representative to effect the scheduling of Gas deliveries to the Plant, and Shell shall coordinate nomination and scheduling activities directly with such representative, giving sufficient time to meet the deadlines of Transco and SONAT so that Gas can be delivered in a manner that will conform to the applicable Requests for Energy. If either Party becomes aware that actual deliveries at a Gas Delivery Point are greater or less than the scheduled deliveries at such Gas Delivery Point, such Party shall promptly notify the other Party.

(i)       Gulf Power shall nominate Gas for delivery to the Plant in amounts and at rates of delivery that, in conformance with Exhibits 5.2, 7.3 and 8.4, will allow the Plant to meet the Request for Energy that Gulf Power has submitted or intends to submit for the applicable Day, having regard for the then current expected heat rate of the Plant at the levels of output requested by Gulf Power (but without affecting the Parties’ rights under Section 8.3). In the event Shell uses any

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Natural Gas scheduled by Gulf Power for purposes other than the generation of Energy on behalf of Gulf Power pursuant to Gulf Power’s dispatch instructions and testing required under this Agreement, Shell shall reimburse Gulf Power for the quantity of Natural Gas so used by Shell at the Delivered Gas Price and Shell shall be the Responsible Party for all associated Transco and/or SONAT imbalance charges.

(j)       Gas to be received by Owner hereunder shall be delivered on behalf of Gulf Power according to established pipeline nomination guidelines and scheduling practices as set forth in Transco’s or SONAT’s, as the case may be, FERC gas tariff or electronic bulletin board or other primary means of communication with customers, but the Parties recognize that, due to operating conditions, the quantities of Gas received and delivered may not be in balance on any particular Day. The Parties shall use commercially reasonable efforts to avoid any imposition of imbalance charges. If Transco or SONAT issues an invoice that includes imbalance charges related to this Agreement, the Parties shall determine the validity as well as the cause of such imbalance charges.

(k)      Shell shall assume that all Gas delivered to the Plant and received by Owner in response to a Request for Energy has been properly nominated and confirmed by Gulf Power. To the extent that Gulf Power issues a Request for Energy that requires the Plant to operate at an output greater than or less than is possible with the Gas delivered on behalf of Gulf Power meeting the specifications required by this Agreement, the provisions of Section 7.3 shall apply and Gulf Power shall be the Responsible Party for all associated Transco and/or SONAT imbalance charges.

(l)       To the extent that Shell does not, within the applicable Energy Delivery Tolerance, deliver the amount of Energy requested in a Request for Energy due to an Unscheduled Outage (other than an Unscheduled Outage caused by the action or inaction of Gulf Power) or an Unpermitted Scheduled Outage and, as a result thereof, Gulf Power incurs an imbalance charge on Transco and/or SONAT, Shell shall be the Responsible Party for all associated Transco and/or SONAT imbalance charges.

(m)     The Responsible Party (as determined according to Sections 6.1(k) and 6.1(l)) shall be liable for and reimburse the other Party for any Transco and/or SONAT cashout costs and losses or penalties incurred by such other Party as a result of the situation causing a Party to be considered the Responsible Party. Payment by Shell to Gulf Power of amounts payable under this Section 6.1(m) shall be made no later than ten Days after receipt by Shell of Gulf Power’s statement therefore, including a copy of the allocation or imbalance statement of the applicable pipeline for the applicable period, as well as a pro-rata calculation of the amount payable. Amounts payable by Gulf Power to Shell under this Section 6.1(m) shall be included in the next Statement to be issued by Shell, including a copy of the allocation or imbalance statement of the applicable pipeline for the applicable period, as well as a pro-rata calculation of the amount payable, and paid according to Article 9.

6.2 Fuel Oil Deliveries. (a) Gulf Power shall have the right to cause Fuel Oil to be delivered bytanker trucks to the Plant at the Fuel Oil Delivery Point. Gulf Power shall keep Shell apprised of the expected delivery schedule for Fuel Oil. All deliveries of Fuel Oil shall be accompanied by documentation of the quantity and quality of the Fuel Oil delivered. Shell shall, subject to the capacity limitations of the Fuel Oil Storage Facilities and the Fuel Oil Unloading Facilities, cause

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Owner to accept Fuel Oil deliveries at the Plant during all hours of each Day.

(b)      As between the Parties, Shell shall be solely responsible for ensuring that (i) the Fuel Oil is unloaded from the tanker trucks, (ii) the Fuel Oil is properly transported, handled, managed, used and disposed of from and after delivery, (iii) the quality of Fuel Oil delivered to the Plant is verified, and (iv) the Fuel Unloading Facilities are sufficient to enable Owner to unload Fuel Oil at a rate of 30,000 gallons of Fuel Oil each hour. If during any Contract Year Gulf Power fails to make sufficient Requests for Energy for Energy fired by Fuel Oil so that an amount of Fuel Oil equal to at least 20% of the Fuel Oil inventory at the beginning of such Contract Year is consumed, Gulf Power shall reimburse Shell for all incremental costs incurred by Shell (or for which Shell is responsible) in ensuring that the Fuel Oil inventory may be burned in the Plant. Such costs may include the cost of disposing of degraded Fuel Oil, blending fresh Fuel Oil and the cost of remedial chemical additives. Gulf Power may request from Shell an estimate of cost for blending and/or other applicable remediation techniques to restore Fuel Oil which has degraded in quality as a result of failure to deplete 20% from inventory in the current Contract Year and Shell shall provide such cost estimates, pursuant to which Gulf Power shall inform Shell of its decision, if any, to burn additional Fuel Oil or pay for remediation.

(c)      As between the Parties, Gulf Power shall be deemed to be in exclusive control and possession of the Fuel Oil delivered under this Agreement, and responsible for any damage or injury caused thereby, prior to the time the Fuel Oil is delivered at the Fuel Oil Delivery Point. After the delivery of Fuel Oil to the Fuel Oil Delivery Point (and with respect to any Fuel Oil that is the subject of Section 6.2(g)), as between the Parties, Shell shall be deemed to be in exclusive control and possession of the Fuel Oil and responsible for any injury or damage caused thereby. Notwithstanding the preceding two sentences, title to all Fuel Oil delivered under this Agreement shall remain with Gulf Power and shall not pass from Gulf Power to Shell.

(d)      If any Fuel Oil tendered by Gulf Power under this Agreement fails to meet the specifications set forth in Exhibit 6.2, Shell may either accept the non-conforming Fuel Oil or require removal of the non-conforming Fuel Oil. If Shell requires removal of non-conforming Fuel Oil, Gulf Power shall be deemed to have failed to deliver such Fuel Oil for purposes of Section 7.3. If Owner burns any non-conforming Fuel Oil, Gulf Power shall have no liability with respect to the non-conforming Fuel Oil.

(e)      If at any time deliveries of Gas to the Plant are interrupted or curtailed for any reason, Gulf Power shall have the right to direct the production of Energy by the Plant using Fuel Oil according to Sections 5.1 and 5.2. During any Month in the Pre-Term Period Shell will not direct the Plant to operate using more than the greater of the amounts of Fuel Oil on a Monthly basis or the amounts of Fuel Oil on a cumulative basis shown in the following table.

Month	Fuel Oil (Gallons)
	Month	Cumulative
June	[**]	[**]
July	[**]	[**]
August	[**]	[**]

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September	[**]	[**]
October	[**]	[**]
November	[**]	[**]
December	[**]	[**]
January	[**]	[**]
February	[**]	[**]
March	[**]	[**]
April	[**]	[**]
May	[**]	[**]

During the First Contract Year Gulf Power shall not request that the Plant operate on Fuel Oil using more than 29,925,000 gallons of Fuel Oil minus the amount of Fuel Oil consumed during the Pre-Term Period. Following the First Contract Year, Gulf Power may not direct the Plant to operate during any period of 12 consecutive Months using more than 95% of the 31,500,000 gallons of Fuel Oil during such 12-Month period pursuant to the Plant’s emissions permit. Gulf Power shall give Shell at least 24 hours’ prior notice of any proposed use of Fuel Oil by the Plant. If Gulf Power requests the use of Fuel Oil upon less than 24 hours’ prior notice, Shell shall use reasonable efforts to accommodate the request. If, more than ten times in any Contract Year, Gulf Power gives such prior notice and then does not actually issue a Request for Energy directing the consumption of Fuel Oil by the Plant, Gulf Power shall reimburse Shell for all reasonable documented incremental costs incurred by Shell (or for which Shell is responsible) in connection with the preparation for using Fuel Oil.

(f)      Shell shall cause Owner to use commercially reasonable efforts to maintain Permits that will allow the Plant to operate using a maximum quantity of 31,500,000 gallons of Fuel Oil in any period of 12 consecutive Months (which quantity will allow the operation of all three Combustion Turbines on Fuel Oil for approximately [**] hours at base load, which is [**] MW at 20°F with no duct firing and no Power Augmentation). Shell will report to Gulf Power the amount of Fuel Oil consumed each Month. Upon request, Shell will report to Gulf Power the current Fuel Oil inventory level. The Operating Committee shall develop procedures for the real time reporting of Fuel Oil inventory and other operating protocols, including nomination, scheduling and delivery, inventory accounting, operations reporting and quality control. Gulf Power shall have the right to order a tank inspection at its sole cost with an independent inspector to determine the quantity and quality of Fuel Oil on site.

(g)       Promptly following the first day of the Operating Term, Shell shall measure and invoice Gulf Power for the existing inventory of Fuel Oil at the Plant to which Shell has title (excluding tank heel), which invoice shall be payable in accordance with Section 9.1. Shell warrants that at the time of such purchase, the Fuel Oil meets the quality specifications as set forth in Exhibit 6.2. Upon payment of same, title to all such Fuel Oil shall pass from Shell to Gulf Power. The price payable by Gulf Power for such Fuel Oil shall be the amount equal to the quantity of such inventory times the average Daily Fuel Oil Price during the one hundred twenty day (120) period immediately

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preceding the first day of the Operating Term. At the end of the Operating Term, Shell shall purchase Gulf Power’s Fuel Oil inventory at the Plant (excluding tank heel) as of the last day of the Term. Gulf Power warrants that at the time of such purchase, the Fuel Oil meets the quality specifications as set forth in Exhibit 6.2. Shell shall pay Gulf Power for such inventory within ten (10) Days of receiving Gulf Power’s invoice at an amount equal to the quantity of such inventory times the average Daily Fuel Oil Price during the one hundred twenty day (120) period immediately preceding the last day of the Operating Term. The Parties shall use an independent inspector to determine the quantity and quality of the Fuel Oil purchased and sold at the beginning and end of the Term.

(h) Shell shall at its cost and risk cause Owner to operate and maintain the Fuel Oil Storage Facilities and the Fuel Oil Unloading Facilities.

6.3 Intentionally Omitted.

ARTICLE 7

OPERATION OF THE PLANT

7.1 Maintenance Scheduling. (a) Exhibit 7.1 sets forth the long-term preventive maintenance program for the Plant. Subject to Sections 7.1(b), 7.1(c) and 7.1(d), the program may be altered from time to time based on later manufacturers’ releases pertaining to major items of equipment of the Plant and the operating experience of the Plant.

(b)      Prior to June 1, 2010, the permitted Scheduled Outages dates and capacities are: [**]  On or before January 10 of each calendar year after 2009, Gulf Power shall provide Shell with non-binding estimates for each Month of the 12-Month period commencing on May 15 of such calendar year of (i) the amounts of Requested Energy, (ii) the number of Combustion Turbine Starts and (iii) the number of hot, warm and cold Steam Turbine Starts. On or before February 20 of each calendar year, Shell shall submit to Gulf Power Owner’s proposed schedule of Scheduled Outages for the 12-Month period commencing on May 15 of such calendar year. The proposed schedule to be provided by Shell shall, for each Scheduled Outage in such Contract Year, specify (1) the number of Generating Units that will operate, (2) the expected level of Plant Capability, if any, available from these Generating Units, (3) the expected timing and duration of the Scheduled Outage, and (4) a description of the major maintenance or overhaul activities to be performed which are the critical path activities for such Scheduled Outage (the “Scope” of the Scheduled Outage). Each Scheduled Outage identified by Shell shall be scheduled to be performed during the Off Peak Period and (x) if scheduled for the spring period, be scheduled to be completed no later than May 15, and (y) if scheduled for the fall period, be scheduled to be completed no later than November 15 (in each case, the “Permitted Scheduled Outage Completion Date”). Within 20 days following receipt by Gulf Power of Owner’s proposed Scheduled Outage schedule, Gulf Power shall notify Shell whether Gulf Power approves the number, duration, timing and Scope of Scheduled Outages in Owner’s proposed Scheduled Outage schedule. The number, duration, timing and Scope of the Scheduled Outages in Owner’s proposed schedule of Scheduled Outages shall be deemed approved by Gulf Power if Gulf Power does not notify Shell of its disapproval within the time limit set forth above in this Section 7.1(b). If Gulf Power has a reasonable objection to the number, duration, timing or scope of the Scheduled Outages in the proposed Scheduled Outage schedule, it shall provide Shell with

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proposed changes to the Scheduled Outage schedule, and Shell shall use commercially reasonable efforts to negotiate such changes with Owner. If Shell is unable to resolve its differences with Owner within 60 days of receipt of Gulf Power’s proposed changes to the Scheduled Outages schedule in a manner reasonably satisfactory to Gulf Power, Shell agrees to use the dispute resolution procedures available to it and Gulf Power agrees to be bound by the decision of any independent arbitrator resolving this dispute. Gulf Power agrees to cooperate with Shell in any such dispute resolution process and, if requested by Gulf Power, Shell shall include Gulf Power, as an interested party, in such proceedings. The Scheduled Outages set forth on the final schedule, as it may be adjusted according to Sections 7.1(c), 7.1(d) and 7.1(e) and Transmission Outages are referred to as “Permitted Scheduled Outages.” Any Scheduled Outage not set forth on the final schedule, including any extension of a Scheduled Outage beyond its duration as set forth on the final schedule and including any reduction in the Plant Capability as set forth on the final schedule, is referred to as an “Unpermitted Scheduled Outage.” Notwithstanding anything to the contrary, no Scheduled Outage may take place during the Peak Period, except that (x) minor short-term Scheduled Outages for inspection and maintenance may take place during the Off Peak Hours in the Peak Period, (y) Scheduled Outages that are necessary to repair unforeseen equipment problems may take place during the Peak Period to the extent that such repairs cannot, according to Prudent Generator Practices, be completed in or deferred until the Off Peak Period and (z) Transmission Outages may take place during the Peak Period to the extent that Shell is unable, after using diligent efforts, to cause the applicable Transmission Authority or Transmission Providers to agree to reschedule the Scheduled Outage to the Off Peak Period, it being understood that any portion of any Scheduled Outages during the Peak Period (other than Transmission Outages), regardless of the reason, will constitute Unpermitted Scheduled Outages and will not reduce the Permitted Schedule Outage Capability for purposes of Gulf Power issuing Requests for Energy.

(c)      After the final Scheduled Outage schedule is established according to Section 7.1(b), Gulf Power may request changes in the timing of Scheduled Outages (but not the total number of hours of Permitted Scheduled Outages). Any such request shall accommodate the provisions of Section 7.1(d) and shall be limited by the applicable Permitted Scheduled Outage Completion Date. In such event, Shell shall promptly inform Gulf Power of whether it is possible to reschedule the Scheduled Outage and, if it is possible, the costs that are expected to be incurred by Owner as a result of the change requested by Gulf Power. If Gulf Power requests that a Scheduled Outage take place at an earlier date than provided for in the approved Scheduled Outage schedule, such costs may include the costs associated with the loss of useful parts life and the costs associated with the related acceleration of the future maintenance schedule. If it is possible to reschedule the Scheduled Outage and if Gulf Power approves such costs, Shell shall make the changes to the Scheduled Outage schedule requested by Gulf Power. Gulf Power shall reimburse Shell for all reasonable documented out-of-pocket costs, if any, actually incurred by Shell (or for which Shell is responsible) in changing the Scheduled Outage schedule as requested by Gulf Power.

(d)      The Scheduled Outage schedule proposed by Shell for each Contract Year according to Section 7.1(b) may include an annual examination of the Plant’s Steam Turbine, Steam Turbine generator, condenser and all associated Steam Turbine generator auxiliary equipment (the “ST Examination”), provided that no separate ST Examination will be scheduled during Contract Years in which a major maintenance of the Steam Turbine is scheduled (“ST Scheduled Maintenance”). The ST Examination will be scheduled to end no later than April 15 of each Contract

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Year. If the ST Examination reveals that additional inspections or repairs or maintenance work is required on the Steam Turbine, Steam Turbine generator, condenser or associated Steam Turbine generator auxiliary equipment according to Prudent Generator Practices and manufacturers’ recommendations (collectively, “ST Interim Maintenance”) and such ST Interim Maintenance cannot, according to Prudent Generator Practices, be deferred until the next ST Scheduled Maintenance, Shell shall promptly notify Gulf Power thereof and provide Gulf Power with information and documentation (including specific recommendations of the equipment manufacturers) describing and supporting the need for the ST Interim Maintenance. The Parties shall then endeavor to agree reasonably on the duration and timing of the ST Interim Maintenance. The duration of the ST Interim Maintenance, up to the agreed duration thereof, shall constitute a Permitted Scheduled Outage, it being understood that any portion of any Permitted Scheduled Outage during the Peak Period, regardless of the reason, will not reduce the Permitted Schedule Outage Capability for purposes of Gulf Power issuing Requests for Energy.

(e)      Shell may shift the start date of a Scheduled Outage, or extend a Scheduled Outage by providing Gulf Power with notice at least 40 days before the earlier of the original Scheduled Outage start date or the new Scheduled Outage start date, unless the change in the Scheduled Outage start date or duration would result in more Generating Units being in a Scheduled Outage than would have occurred under the original schedule, in which case Shell will provide Gulf Power with at least 60 days prior notice for the Scheduled Outage change. Any such notice must include (i) the new dates and duration of the Scheduled Outage, (ii) the reason for the change in dates and (iii) the Permitted Scheduled Outage Capability, if any, during the Scheduled Outage. Any change described in this Section 7.1(e) shall be subject to Gulf Power’s approval. Notwithstanding Gulf Power’s approval, to the extent the duration of a Scheduled Outage is extended beyond the originally scheduled duration (or, in the case of ST Maintenance, beyond the agreed duration), the extended portion of the Scheduled Outage shall be considered an Unpermitted Scheduled Outage and will not reduce the Permitted Schedule Outage Capability for purposes of Gulf Power issuing Requests for Energy.

7.2 Requests for Energy. To the extent that it is able to do so in accordance with (a) the Generating Unit Operating Principles, (b) Prudent Generator Practices, and (c) Applicable Laws, Shell shall cause the Plant to respond to each Request for Energy. In the absence of a Shell default under Section 11.5(d), (f), (g) or (i), the remedies for Shell’s failure to cause the Plant to respond to a Request for Energy are limited to the provisions of Sections 8.7 and 8.8. If Shell has elected to provide Energy from an Alternate Resource and if Gulf Power elects to schedule Energy for delivery on the next Business Day, Gulf Power shall provide its schedule no later than 8:30 a.m. Central Prevailing Time on the Business Day prior to the Day of delivery for deliveries from an Alternate Resource. This Day-ahead Scheduling Instruction will also include any electric deliveries from midnight to midnight for any calendar Days that precede the next Business Day (i.e. weekends and holidays). Gulf Power shall also provide a non-binding, good faith estimate of its scheduling instructions for the twenty-four (24) hour period following the next Business Day. For purposes of scheduling an Alternate Resource, Gulf Power’s schedule options for such resource shall be determined by the number of Generating Units available. In the event one Generating Unit is unavailable, Gulf Power may Schedule the Alternate Resource for 33% of the Contract Capacity. In the event two Generating Units are unavailable, Gulf Power may Schedule the Alternate Resource for 66% of the Contract Capacity. If all three Generating Units are unavailable, Gulf Power may

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Schedule the Alternate Resource for either 50% of the Contract Capacity or the Contract Capacity. Gulf Power will be required to accept and pay for Energy during ramp up and ramp down periods.

7.3 Response to Non-Conforming Requests for Energy. A “Non-Conforming Request for Energy” means any Request for Energy that would require (a) during a Scheduled Outage, output at a level greater than the Permitted Scheduled Outage Capability applicable to such Scheduled Outage, or (b) the Plant to perform outside the performance parameters set forth in the Generating Unit Operating Principles, or (c) the Plant to operate at an output higher than is possible with the Fuel delivered by Gulf Power, meeting the specifications required by this Agreement, or (d) the Plant to generate Energy using a portion of the Contract Capacity impaired by a Cover Event during the time that such impaired Contract Capacity is the subject of an effective Election Period under Section 5.7, or (e) the Plant to deliver Energy into the system of the Transmission Provider when there is no Energy Interconnection Agreement or other interconnection arrangements in place with the Transmission Provider. Shell shall inform Gulf Power promptly after Shell is actually aware that a Non-Conforming Request for Energy is in effect. Pending receipt of Gulf Power’s modification of the Non-Conforming Request for Energy, the Non-Conforming Request for Energy shall be deemed to be reduced or increased, as the case may be, to the Request for Energy that could be in effect without resulting in it being considered a Non-Conforming Request for Energy. If a Request for Energy is a Non-Conforming Request for Energy according to the express terms of the first sentence of this Section 7.3 and is deemed increased or decreased according to the immediately preceding sentence, Requested Energy for any hour covered by such Request for Energy shall equal the amount specified in such Request for Energy as so increased or decreased. In all other cases, Requested Energy for any hour shall equal the amount specified in the applicable Request for Energy, notwithstanding that the Plant may be unable to operate at such level due to a Force Majeure event, an Unpermitted Scheduled Outage, a Permitted Scheduled Outage, a Cover Event or any other cause whatsoever, whether or not within the control of Shell.

7.4 Operation. (a) Shell shall cause the Owner to manage, control, operate and maintain the Plant in a manner consistent with Prudent Generator Practices. Shell shall take into account Gulf Power’s right to schedule the Plant, applicable planning standards and operating policies of the SERC and NERC, and the Operating Procedures to be developed by the Operating Committee (provided that such Operating Procedures do not deviate from this Agreement). Shell shall: (i) be in compliance with all Applicable Laws necessary to fulfill its obligations under this Agreement and (ii) shall seek to ensure that Owner diligently seeks to maintain compliance with all Applicable Laws necessary for Owner to fulfill its obligations under the Tenaska ECA. For the avoidance of doubt, the requirements of this Section 7.4 shall not be interpreted to limit Gulf Power’s scheduling rights as provided for elsewhere in this Agreement.

(b)      Shell and Gulf Power shall use commercially reasonable efforts to mutually develop and agree upon written Operating Procedures that are consistent with this Agreement within three (3) months of execution of this Agreement or such other mutually agreeable time. Topics covered shall include deliveries of energy during start up, the method of day-to-day communications, daily capacity availability and energy reports, Plant operations logs, reactive power output, minimum run times, ramp rates, minimum down times, coordination of maintenance scheduling, designation of confidential information, and such other matters as the Operating Representatives shall agree are appropriate. The Operating Representatives shall be responsible for modifying, from time to time,

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these Operating Procedures in writing to reflect agreed upon changes. In the event of inconsistency or conflict between the Operating Procedures and specific terms of this Agreement, the specific terms of this Agreement shall take precedence.

(c)      The Plant shall be operated by qualified and trained personnel consistent with the terms of the Tenaska ECA.

7.5 Operating Committee. The Parties shall establish an Operating Committee comprised of two (2) Operating Representatives. Shell and Gulf Power, as the case may be, shall provide written notice of such appointments to the other Party. Such appointments may be changed at any time by similar written notice. The Operating Representatives shall meet as necessary, but not less often than once each calendar year, at a mutually agreeable time and place upon prior written notice. The Operating Representatives shall represent the Parties in all matters arising hereunder that may be delegated to them by mutual agreement of the Parties, but shall not have any authority to modify or amend the terms of this Agreement. Each Party shall cooperate in providing to the Operating Representatives all information required in the performance of their duties. If the Operating Representatives are unable to agree on any matter falling under their jurisdiction, such matter shall be submitted to senior officers for discussion and resolution. All decisions and agreements made by the Operating Representatives or their principals shall be evidenced in writing.

7.6 Tenaska ECA Amendment. Shell shall endeavor to cause Owner to consent to an amendment to the Tenaska ECA (“Amendment No. 5”) allowing greater flexibility with respect to Steam Turbine Starts (such amendment to be based upon proposals developed by Gulf Power). Should Owner consent to such amendment on terms that are reasonably acceptable to Shell and Gulf Power, then Shell shall cause the Tenaska ECA to be so amended.

7.7 Transmission Service to Deliver Energy and Capacity from the Energy Point of Delivery. Gulf Power shall bear all costs and responsibility for the transmission service necessary to deliver Energy and Capacity from the Energy Point of Delivery during the Operating Term and shall bear all risks associated with the adequacy, reliability, failure or curtailment of such transmission service for any reason.

7.8 Transmission Interconnection Service to the Energy Point of Delivery. Shell shall bear all costs and responsibility for the transmission interconnection service necessary to achieve the purpose of this Agreement during the Operating Term and shall bear all risks associated with the adequacy, reliability, failure or curtailment of such transmission interconnection service for any reason.

ARTICLE 8

OTHER PAYMENTS; TAXES

8.1 [Intentionally Omitted]

8.2 Payments for Start Up Energy. (a) When no Generating Units are operating, Gulf Power shall reimburse Shell for the reasonably incurred cost to Owner of Energy used to Start the Generating Units from zero load. However, when a Generating Unit is Started from zero load

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following an Outage of the Generating Unit, Shell shall bear the cost of Energy used to Start the Generating Units from zero load. When at least one Generating Unit is operating and one or more additional Generating Units are started, Shell shall cause Owner to use Energy generated by the operating Generating Unit(s) to Start such additional Generating Units and shall compensate Gulf Power for Gulf Power’s cost of the Fuel used to generate such Energy. Gulf Power’s obligation to reimburse Shell for Energy under this Section 8.2(a) shall be limited to the cost of [**] MWh per Start of a Generating Unit and Gulf Power’s obligation to reimburse for capacity charges associated with Start Energy shall be limited to [**] MW for the entire Plant at any time.

(b)      Gulf Power shall have the right, upon 12 months’ prior notice to Shell, to supply the Energy required for Starts of Generating Units in lieu of Gulf Power’s reimbursement obligation under Section 8.2(a). If Gulf Power supplies Energy for Starts under this Section 8.2(b), when a Generating Unit is Started from zero load following an Outage of a Generating Unit, Shell shall pay Gulf Power for Energy supplied by Gulf Power for such Start at a rate of $[**] per MWh, escalating at three percent per year beginning June 1, 2010. If Gulf Power supplies Energy under this Section 8.2(b), in circumstances where Gulf Power would have a reimbursement obligation under Section 8.2(a), Shell shall reimburse Gulf Power (at the rate specified in the preceding sentence) for all Energy supplied in excess of two MWh per Start of a Generating Unit and (at Gulf Power’s cost of capacity) for capacity in excess of ten MW for the entire Plant at any time.

8.3 Heat Rate. (a) The heat rate of the Plant shall be tested for each Contract Year other than the First Contract Year at the time the capacity of the Plant is required to be tested according to Section 4.3 with respect to such Contract Year (or portion thereof) (each a “Heat Rate Test Date”). The reference heat rate (expressed in MMBtu/MWh) for the Plant (the “Reference Heat Rate”) shall be determined by Shell for the First Contract Year during the Pre-Term Period utilizing the procedure as set forth in Exhibit 8.3 and promptly communicated to Gulf Power and for each subsequent Contract Year shall be determined for each Heat Rate Test Date in accordance with Exhibit 8.3, based on Factored Fired Hours of the Combustion Turbines as of such Heat Rate Test Date.

(b)      Shell shall cause a Heat Rate Test of the Plant to be conducted on each Heat Rate Test Date sequentially with the test of the Plant’s capacity according to Section 4.3. Shell shall give Gulf Power at least eight Days’ prior notice of each Heat Rate Test and Gulf Power or its representatives may attend each Heat Rate Test. If final test results are not available by the first day of the immediately succeeding Contract Year, the Heat Rate Payments for such succeeding Contract Year will be based on the preliminary report of test results referred to in Exhibit 4.2 until the results of the Heat Rate Test are available and used to determine the Heat Rate Payments for the applicable Contract Year. When the final test results are available, the Parties shall make an adjustment of the Heat Rate Payments from the beginning of the applicable Contract Year to reflect the Tested Heat Rate based on the final test results. If a Heat Rate Test for a Contract Year is conducted after the beginning of such Contract Year, the Reference Heat Rate set for such Contract Year pursuant to Section 8.3(a) nevertheless shall apply from the first day of such Contract Year; provided, however, to the extent necessary for any payments or calculations using the Reference Heat Rate for such Contract Year prior to the preliminary report of test results, the Parties on an interim basis shall use the Reference Heat Rate for the prior Contract Year until such preliminary report of test results is available and then shall make adjustments of such payments and calculations in accordance with the

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preliminary report of test results and final test results as provided above. For the avoidance of doubt, the Reference Heat Rate will be calculated in accordance with Exhibit 8.3 and the value of the Average Factored Fired Hours will be the value as calculated on the Heat Rate Test Date, regardless of whether the Heat Rate Test Date is after the beginning of such Contract Year.

(c)      If Owner reasonably believes that, due to equipment malfunction or other causes, the results of a Heat Rate Test are not representative of the actual heat rate capability of the Plant, Shell shall cause Owner to promptly correct the equipment malfunction or other causes and the Heat Rate Test shall be re-run as soon as practicable following the correction of the equipment malfunction or other causes. Until the results of the re-test are available, Heat Rate Payments will be based upon a deemed Tested Heat Rate for such period equal to the higher of (i) the Tested Heat Rate for the later of the Pre-Term Period if the event happens in the First Contract Year or the immediately preceding Contract Year if the event happens in any Contract Year other than the First Contract Year, and (ii) the Reference Heat Rate for the applicable Heat Rate Test Date. When the results of the re-test are available, the Parties shall make an adjustment of the Heat Rate Payments to reflect the Tested Heat Rate determined in the re-test, which adjustment shall be effective from the beginning of the applicable Contract Year.

(d) If the Tested Heat Rate of the Plant during a Heat Rate Test is higher than 97.02% of the Reference Heat Rate for the applicable Heat Rate Test Date and lower than 102.98% of the Reference Heat Rate for the applicable Heat Rate Test Date, there shall be no Heat Rate Payment for the applicable Contract Year.

(e) If the Tested Heat Rate of the Plant during a Heat Rate Test is lower than 97.02% of the Reference Heat Rate for the applicable Heat Rate Test Date, Gulf Power shall make a Heat Rate Payment to Shell according to Article 9 for each Month (or portion thereof) during the applicable Contract Year in an amount calculated as follows:

Where:
HRP	=	Heat Rate Payment for the applicable Month (or portion thereof).
RHR	=	Reference Heat Rate for the immediately preceding Heat Rate Test Date.
THR	=	Tested Heat Rate with respect to the immediately preceding Heat Rate Test Date.
d	=	Each Gas Day during the applicable Month (or portion thereof).

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n	=	Total number of Gas Days during the applicable Month (or portion thereof).
GQd	=	Quantity of Gas, if any, consumed by the Plant on Gas Day d.
DGIPd	=	Daily Gas Index Price for Gas delivered on Gas Day d.
FOC	=	Gulf Power’s total actual cost of the Fuel Oil, if any, consumed by the Plant during the applicable Month (or portion thereof).

(f)        If the Tested Heat Rate of the Plant during a Heat Rate Test is higher than 102.98% of the Reference Heat Rate for the applicable Heat Rate Test Date, Shell shall make a Heat Rate Payment to Gulf Power according to Article 9 for each Month (or portion thereof) during the applicable Contract Year in an amount calculated as follows:

Where:
HRP	=	Heat Rate Payment for the applicable Month (or portion thereof).
THR	=	Tested Heat Rate with respect to the immediately preceding Heat Rate Test Date.
RHR	=	Reference Heat Rate for the immediately preceding Heat Rate Test Date.
d	=	Each Gas Day during the applicable Month (or portion thereof).
n	=	Total number of Gas Days during the applicable Month (or portion thereof).
GQd	=	Quantity of Gas, if any, consumed by the Plant on Gas Day d.
DGIPd	=	Daily Gas Index Price for Gas delivered on Gas Day d.
FOC	=	Gulf Power’s total actual cost of the Fuel Oil, if any, consumed by the Plant during the applicable Month (or portion thereof).

8.4 Payments for Steam Turbine Starts. (a) Intentionally Omitted.

(b) Except as otherwise provided in Section 8.4(e), the maximum number of Cold

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Steam Turbine Starts plus Warm Steam Turbine Starts for any Contract Year shall be [**] (except for the First Contract Year, which shall be equal to [**] less the sum of the Cold Steam Turbine Starts and Warm Steam Turbine Starts utilized during the Pre-Term Period by Shell); provided, however, the maximum number of Cold Steam Turbine Starts for any Contract Year shall be [**] (except for the First Contract Year, which shall be equal to [**] less the number of Cold Steam Turbine Starts utilized by Shell during the Pre-Term Period). The maximum number of Hot Steam Turbine Starts for any Contract Year shall be [**] minus the total number of Cold Steam Turbine Starts and Warm Steam Turbine Starts for such Contract Year (except that for the First Contract Year, the maximum number of Hot Steam Turbine Starts shall be equal to the [**] minus the total number of Cold Steam Turbine Starts, Warm Steam Turbine Starts and Hot Steam Turbine Starts utilized by Shell during the Pre-Term Period less the total number of Cold Steam Turbine Starts and Warm Steam Turbine Starts used during the First Contract Year). The total maximum number of Steam Turbine Starts (Cold Steam Turbine Starts plus Warm Steam Turbine Starts plus Hot Steam Turbine Starts) shall not exceed [**]. For purposes of measuring the time between any Shutdown of the Steam Turbine and the next Start of the Steam Turbine (including in applying the definition of “ST Start Reduction”), the time from the opening of the last Generating Unit circuit breaker associated with such Shutdown to the time of the closing of the first Generating Unit circuit breaker associated with such Start shall be used. During the Pre-Term Period, Shell will not use more than the greater of the number of Steam Turbine Starts on a Monthly basis or the number of Steam Turbine Starts on a cumulative basis shown in the following table; provided, however, if Amendment No. 5 is not in full force and effect, the numbers shown in the table will be recalculated by applying the fraction having a numerator of [**] and a denominator of [**] to the numbers in the table below.

Month	Cold Starts		Warm Plus Cold Starts		Cold Plus Warm Plus Hot Starts
	Monthly	Cumulative	Monthly	Cumulative	Monthly	Cumulative
June	[**]	[**]	[**]	[**]	[**]	[**]
July	[**]	[**]	[**]	[**]	[**]	[**]
August	[**]	[**]	[**]	[**]	[**]	[**]
September	[**]	[**]	[**]	[**]	[**]	[**]
October	[**]	[**]	[**]	[**]	[**]	[**]
November	[**]	[**]	[**]	[**]	[**]	[**]
December	[**]	[**]	[**]	[**]	[**]	[**]
January	[**]	[**]	[**]	[**]	[**]	[**]
February	[**]	[**]	[**]	[**]	[**]	[**]
March	[**]	[**]	[**]	[**]	[**]	[**]
April	[**]	[**]	[**]	[**]	[**]	[**]
May	[**]	[**]	[**]	[**]	[**]	[**]

(c)      For the First Contract Year, Gulf Power shall pay Shell for each Steam Turbine Start during any Month an amount determined by multiplying the total of the Steam Turbine Start Charges paid to Owner during the 12-Month period inclusive of both the Pre-Term Period and the First Contract Year by a fraction, the numerator of which is the sum of the following Steam Turbine

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Start fees for each Steam Turbine Start that occurs in the First Contract Year and the denominator of which is the sum of the following Steam Turbine Start fees for each Steam Turbine Start that occurs in each of the Pre-Term Period and the First Contract Year. The Steam Turbine Start fees will equal (i) $[**] for any Hot Steam Turbine Starts plus any Warm Steam Turbine Starts (that occur less than thirteen hours since Shutdown incurred and (ii) the Steam Turbine Start fees shown in the following table for any Cold Steam Turbine Starts plus any Warm Steam Turbine Starts (that occur greater than thirteen hours since Shutdown). For the avoidance of doubt for use of the following table, the total number of Starts on the beginning of the first Day of the Pre-Term Period shall equal zero and the total number of Starts on the beginning of the first Day of the First Contract Year shall equal zero.

Cold Steam Turbine Starts Plus Warm Steam Turbine Starts*
Start	Start Charge ($)
[**]	[**]
[**]	[**]
[**]	[**]

* Warm Steam Turbine Starts that occur greater than thirteen hours since Shutdown.

For each subsequent Contract Year, Gulf Power shall pay to Shell as the Start Charge for each Steam Turbine Start during any Month $[**] multiplied by the Escalation Factor applicable to such Month; provided that for any Cold Steam Turbine Starts plus any Warm Steam Turbine Starts that occur greater than thirteen (13) hours since Shutdown, that are in excess of [**] per Contract Year, the Start Charge for each such Steam Turbine Start shall be increased by $[**], such increased amount to be escalated at 4% per year beginning with January 1, 2010. In addition to all other charges, an incremental Start Charge for any Cold Steam Turbine Start plus any Warm Steam Turbine Start that occur more than 13 hours since the previous Shutdown in excess of [**] such Starts per year shall be $[**] to be escalated at 4% per year beginning on January 1, 2010.

(d)      For purposes of Sections 8.4(b) and 8.4(c), a Steam Turbine Start shall include the commencement of operation of the Steam Turbine following a System Trip (as defined in the “Combustion Turbine Starts” section of Exhibit 8.4).

(e)      If Amendment No. 5 is not in full force and effect, the allowable number of Cold Steam Turbine Starts, Warm Steam Turbine Starts and Hot Steam Turbine Starts per Contract Year may be reduced by Shell to not more than [**]combined Warm Steam Turbine Starts and Cold Steam Turbine Starts, including not more than [**] Cold Steam Turbine Starts. The maximum number of Hot Steam Turbine Starts shall not be greater than [**] minus the total number of Cold Steam Turbine Starts and Warm Steam Turbine Starts for the applicable Contract Year; provided, however, that Shell gives Gulf Power written notice of such reduction in the allowable number of Starts at least 20 days prior to the beginning of each Contract Year, such notice is based upon Shell’s receipt of confirmation from the Owner demonstrating to Shell reasonable cause that the number of Starts allowable in Section 8.4(b) in excess of the reduced number of Starts set forth in this Section 8.4(e) would result in an adverse economic impact to the Owner in excess of the fees set forth in

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Section 8.4(c) or the reduction in the amount of Availability Payments owed due to the reductions for such additional Starts in the Peak Availability Target and Off-Peak Availability Target. Notwithstanding the foregoing, prior to giving any notice of intent to reduce the allowable number of Starts as set forth herein, Shell shall provide Gulf Power with a proposed new incremental Start Charge and/or new incremental availability target reduction which Gulf Power may choose to accept or reject at its sole option. If Amendment No. 5 is not in full force and effect for the First Contract Year, the allowable number of Cold Steam Turbine Starts, Warm Steam Turbine Starts and Hot Steam Turbine Starts per Contract Year will be reduced by the number of Cold Steam Turbine Starts, Warm Steam Turbine Starts and Hot Steam Turbine Starts utilized by Shell during the Pre-Term Period.

8.5 Combustion Turbine Fired Hour Payments. (a) Gulf Power shall, for each Month during the Operating Term, pay Shell an amount equal to the number of Factored Fired Hours for each Combustion Turbine during such Month multiplied by the Base Fired Hour Rate applicable to such Month.

(b)      The Start Ratio shall equal the sum of (i) the number of Factored Fired Hours of each Combustion Turbine during such Contract Year, divided by (ii) the number of Gulf Power Factored CT Starts during such Contract Year.

(c)      If the Start Ratio for a Contract Year is 30 or higher, the Adjusted Fired Hour Payment for such Contract Year shall be deemed equal to the total of the Fired Hour Payments calculated for each of the Months of such Contract Year according to Section 8.5(a).

(d)      If the Start Ratio for a Contract Year is 20 or higher but less than 30, the Adjusted Fired Hour Payment for such Contract Year shall equal the product of (i) the Factored Fired Hours for such entire Contract Year, multiplied by (ii) the difference of (A) the Tier 1 Fired Hour Rate applicable to such Contract Year minus (B) the product of the Start Ratio for such Contract Year multiplied by the Tier 1 Adjustment Rate for such Contract Year. In such event, (x) if the Adjusted Fired Hour Payment exceeds the total of the Fired Hour Payments for each of the Months of such Contract Year, Gulf Power shall pay to Shell an amount equal to such excess, or (y) if the total of the Fired Hour Payments for each of the Months of such Contract Year exceeds the Adjusted Fired Hour Payment, Shell shall pay to Gulf Power an amount equal to such excess. Any payment under the preceding sentence shall be made at the time of payment of the Statement covering the last Month of the applicable Contract Year.

(e)      If the Start Ratio for a Contract Year is 10 or higher but less than 20, the Adjusted Fired Hour Payment for such Contract Year shall equal the product of (i) the Factored Fired Hours for such entire Contract Year, multiplied by (ii) the difference of (A) the Tier 2 Fired Hour Rate applicable to such Contract Year minus (B) the product of the Start Ratio for such Contract Year multiplied by the Tier 2 Adjustment Rate for such Contract Year. In such event, (x) if the Adjusted Fired Hour Payment exceeds the total of the Fired Hour Payments for each of the Months of such Contract Year, Gulf Power shall pay to Shell an amount equal to such excess, or (y) if the total of the Fired Hour Payments for each of the Months of such Contract Year exceeds the Adjusted Fired Hour Payment, Shell shall pay to Gulf Power an amount equal to such excess. Any payment under the preceding sentence shall be made at the time of payment of the Statement covering the last

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Month of the applicable Contract Year.

(f)      If the Start Ratio for a Contract Year is less than 10, the Adjusted Fired Hour Payment for such Contract Year shall equal the product of (i) the CT Start Rate applicable to such Contract Year, multiplied by (ii) the number of Gulf Power Factored CT Starts during such Contract Year. In such event, at the time of payment of the Statement covering the last Month of the applicable Contract Year: (x) Shell shall refund to Gulf Power the total of all Fired Hour Payments for each of the Months of such Contract Year, and (y) Gulf Power shall pay to Shell the Adjusted Fired Hour Payment for such Contract Year.

(g)      For the First Contract Year, if (a) the Adjusted Fired Hour Payment calculated over the 12-Month period inclusive of both the Pre-Term Period and the First Contract Year minus (b) the product of (i) the Minimum Adjusted Fired Hour Charge multiplied by (ii) the arithmetic mean of the Peak Availability Factor and the Off Peak Availability Factor calculated for the period inclusive of both the Pre-Term Period and the First Contract Year is negative, (the “Total Deficit”), Gulf Power shall pay Shell an amount equal to the sum of the percentages for each Month in the First Contract Year shown in the following table multiplied by the Total Deficit. Shell shall include such amount on the Statement following the last Month of the First Contract Year and Gulf Power shall pay such amount to Shell at the time of payment of such Statement.

Month	Minimum Adjusted Fired Hour Charge Deficit in (%) of Total Deficit
June 2009	16
July 2009	16
August 2009	16
September 2009	16
October 2009	3.4
November 2009	3.4
December 2009	3.4
January 2009	5
February 2009	5
March 2009	3.4
April 2009	3.4
May 2009	9

For each subsequent Contract Year, if the Adjusted Fired Hour Payment is less than the product of (i) the Minimum Adjusted Fired Hour Charge for such Contract Year multiplied by (ii) the arithmetic mean of the Peak Availability Factor and the Off Peak Availability Factor for such Contract Year, Shell shall include such difference on the Statement covering the last Month of the applicable Contract Year and Gulf Power shall pay such difference to Shell at the time of payment of such Statement.

8.6 Bonus Availability Target and Availability Bonus Payments. For the First Contract Year,

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the Bonus Availability Factor shall be determined for the 12-Month period inclusive of both the Pre-Term Period and the First Contract Year. For this 12-Month period, if such Bonus Availability Factor exceeds the Bonus Availability Target, Gulf Power shall pay to Shell an Availability Bonus Payment calculated according to Section 2 of Exhibit 8.6 but only including those Hours in the First Contract Year that are included in the 30 Days of highest Peak Hour spark spread for the 12-Month period inclusive of both the Pre-Term Period and the First Contract Year in which there was Requested Energy. If for any subsequent Contract Year the Bonus Availability Factor exceeds the Bonus Availability Target, Gulf Power shall pay to Shell an Availability Bonus Payment for such Contract Year calculated according to Section 2 of Exhibit 8.6. The Availability Bonus Payment, if any, for a Contract Year shall be included on the Statement for the last Month of such Contract Year and shall be paid according to Section 9.2.

8.7 Peak Availability Target and Peak Availability Payments. (a) For the First Contract Year, the Peak Availability Factor will be calculated per Exhibit 8.7 for the 12-Month period inclusive of both the Pre-Term Period and the First Contract Year (the “First Contract Year Peak Availability Factor”). If the First Contract Year Peak Availability Factor is less than the Peak Availability Target, the Peak Availability Payment will be calculated according to Section 2 of Exhibit 8.7, using the First Contract Year information and the First Contract Year Peak Availability Factor, Shell shall pay to Gulf Power such Peak Availability Payment. If in any subsequent Peak Availability Measurement Period the Peak Availability Factor is less than the Peak Availability Target, Shell shall pay to Gulf Power a Peak Availability Payment for such Peak Availability Measurement Period calculated according to Section 2 of Exhibit 8.7 at the times set forth in Sections 8.7(b) and 8.7(c).

(b)      (1) Except as otherwise set forth in Section 8.7(b)(2), at the end of each Month, the Peak Availability Payment shall be calculated according to Exhibit 8.7, except that such Peak Availability Payment will not be calculated for the entire Peak Availability Measurement Period of the applicable Contract Year but will be calculated on a cumulative basis from the beginning of the Peak Availability Measurement Period of such Contract Year through the end of that Month (the “Cumulative Provisional Peak Availability Amount”). For each Contract Year3, in calculating the Cumulative Provisional Peak Availability Amount at the end of any Month, if the total Base Requested Energy during the Peak Availability Measurement Period from the beginning of the applicable Contract Year through the end of such Month is less than the Interim Peak Target Request Quantity as of the end of such Month (such difference, the “Interim Peak Request Shortfall”), the denominator of the fraction set forth in Section 1 of Exhibit 8.7 shall be increased by an amount equal to the Interim Peak Request Shortfall as of the end of such Month and the numerator of such fraction shall be increased by an amount equal to the Interim Peak Request Shortfall multiplied by the Peak Availability Target for the applicable Peak Availability Measurement Period. The Cumulative Provisional Peak Availability Amount as of the end of any Month shall not exceed the product of (i) the Peak Availability Target for such Contract Year minus the Peak Availability Factor for such Contract Year calculated on a cumulative basis through the end of the applicable Month, multiplied by (ii) the Capacity Payments payable by Gulf Power in respect of such Contract Year from the beginning of such Contract Year through the end of the applicable Month (which Capacity

_________________________

³ For purposes of this provision, the First Contract Year shall be deemed to include the Pre-Term Period and the Pre-Term Activities.

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Payments shall be determined taking into account any adjustment under Section 4.1(b) but without regard to any adjustments under Section 4.1(c) or 4.1(d)), multiplied by (iii) 2.9. In addition, the Cumulative Provisional Peak Availability Amount as of the end of any Month, when added to the Cumulative Provisional Off Peak Availability Amount as of the end of such Month, shall not exceed two times the total of the Capacity Payments payable by Gulf Power in respect of such Contract Year from the beginning of such Contract Year through the end of the applicable Month (which Capacity Payments shall be determined taking into account any adjustment under Section 4.1(b) but without regard to any adjustments under Section 4.1(c) or 4.1(d)).

(b)(2)  If Amendment No. 5 is in full force and effect, (i) the provisions of this Section 8.7(b)(2) shall supercede the provisions of Section 8.7(b)(1) and Sections 8.7(c) and 8.7(d) shall be deemed deleted and (ii) at the end of each Calendar Year, the Peak Availability Payment shall be calculated according to Exhibit 8.7.

(c)      If the Cumulative Provisional Peak Availability Amount as of the end of a Month exceeds the difference of (i) the sum of all Monthly Provisional Peak Availability Payments, if any, theretofore made by Shell to Gulf Power in respect of the applicable Contract Year, minus (ii) the sum of all Monthly Provisional Peak Availability Refunds, if any, theretofore made by Gulf Power to Shell in respect of the applicable Contract Year, then Shell shall include such excess (the “Monthly Provisional Peak Availability Payment”) on the Statement for that Month. Shell shall pay the Monthly Provisional Peak Availability Payment to Gulf Power according to Section 9.2.

(d)      If as of the end of a Month the difference of (i) the sum of all Monthly Provisional Peak Availability Payments, if any, theretofore made by Shell to Gulf Power in respect of the applicable Contract Year, minus (ii) the sum of all Monthly Provisional Peak Availability Refunds, if any, theretofore made by Gulf Power to Shell in respect of the applicable Contract Year exceeds the Cumulative Provisional Peak Availability Amount as of the end of such Month, then Shell shall include such excess (the “Monthly Provisional Peak Availability Refund”) on the Statement for that Month. Gulf Power shall pay the Monthly Provisional Peak Availability Refund to Shell according to Section 9.2.

8.8 Off Peak Availability Target and Off Peak Availability Payments. (a) For the First Contract Year, the Off Peak Availability Factor will be calculated per Exhibit 8.8 for the 12-Month period inclusive of both the Pre-Term Period and the First Contract Year (the “First Contract Year Off Peak Availability Factor”). If the First Contract Year Off Peak Availability Factor is less than the Off Peak Availability Target, the Off Peak Availability Payment will be calculated according to Section 2 of Exhibit 8.8, using the First Contract Year information and the First Contract Year Off Peak Availability Factor, Shell shall pay to Gulf Power such Off Peak Availability Payment. If in any subsequent Off Peak Availability Measurement Period the Off Peak Availability Factor is less than the Off Peak Availability Target, Shell shall pay to Gulf Power an Off Peak Availability Payment for such Off Peak Availability Measurement Period calculated according to Section 2 of Exhibit 8.8.

(b)      (1) Except as otherwise provided in Section 8.8(b)(2), at the end of each Month, the Off Peak Availability Payment shall be calculated according to Exhibit 8.8, except that (i)

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such Off Peak Availability Payment will not be calculated for the entire Off Peak Availability Measurement Period of the applicable Contract Year but will be calculated on a cumulative basis from the beginning of the Off Peak Availability Measurement Period of such Contract Year through the end of that Month, and (ii) the variable CPm in Section 2 of Exhibit 8.8 shall be the total of the Capacity Payments payable by Gulf Power in respect of such Contract Year from the beginning of such Contract Year through the end of the applicable Month (which Capacity Payments shall be determined taking into account any adjustment under Section 4.1(b) but without regard to any adjustments under Section 4.1(c) or 4.1(d)) (the “Cumulative Provisional Off Peak Availability Amount”). For each Contract Year4, in calculating the Cumulative Provisional Off Peak Availability Amount at the end of any Month, if the total Base Requested Energy during the Off Peak Availability Measurement Period from the beginning of the applicable Contract Year through the end of such Month is less than the Interim Off Peak Target Request Quantity as of the end of such Month (such difference, the “Interim Off Peak Request Shortfall”), the denominator of the fraction set forth in Section 1 of Exhibit 8.8 shall be increased by an amount equal to the Interim Off Peak Request Shortfall as of the end of such Month and the numerator of such fraction shall be increased by an amount equal to the Interim Off Peak Request Shortfall multiplied by the Off Peak Availability Target for the applicable Off Peak Availability Measurement Period.

(b)(2) If Amendment No. 5 is in full force and effect, (i) the provisions of this Section 8.8(b)(2) shall supercede the provisions of Section 8.8(b)(1) and Sections 8.8(c) and 8.8(d) shall be deemed deleted and (ii) at the end of each Calendar Year, the Peak Availability Payment shall be calculated according to Exhibit 8.8.

(c)      If the Cumulative Provisional Off Peak Availability Amount as of the end of a Month exceeds the difference of (i) the sum of all Monthly Provisional Off Peak Availability Payments, if any, theretofore made by Shell to Gulf Power in respect of the applicable Contract Year, minus (ii) the sum of all Monthly Provisional Off Peak Availability Refunds, if any, theretofore made by Gulf Power to Shell in respect of the applicable Contract Year, then Shell shall include such excess (the “Monthly Provisional Off Peak Availability Payment”) on the Statement for that Month. Shell shall pay the Monthly Provisional Off Peak Availability Payment to Gulf Power according to Section 9.2.

(d)      If as of the end of a Month the difference of (i) the sum of all Monthly Provisional Off Peak Availability Payments, if any, theretofore made by Shell to Gulf Power in respect of the applicable Contract Year, minus (ii) the sum of all Monthly Provisional Off Peak Availability Refunds, if any, theretofore made by Gulf Power to Shell in respect of the applicable Contract Year is less than the Cumulative Provisional Off Peak Availability Amount as of the end of such Month, then Shell shall include such excess (the “Monthly Provisional Off Peak Availability Refund”) on the Statement for that Month. Gulf Power shall pay the Monthly Provisional Off Peak Availability Refund to Shell according to Section 9.2.

_________________________

⁴ For purposes of this provision, the First Contract Year shall be deemed to include the Pre-Term Period and the Pre-Term Activities.

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8.9 Limitation on Availability Payments; Nature of Availability Payments. (a) The Peak Availability Payments in respect of any Contract Year shall not exceed the product of (i) the Peak Availability Target for such Contract Year minus the Peak Availability Factor for such Contract Year, multiplied by (ii) the Capacity Payments payable by Gulf Power in respect of such Contract Year (which Capacity Payments shall be determined taking into account any adjustment under Section 4.1(b) but without regard to any adjustments under Section 4.1(c) or 4.1(d)), multiplied by (iii) [**].

(b)      The total of all Availability Payments in respect of any Contract Year shall not exceed (i) [**] payable by Gulf Power in respect of such Contract Year minus (ii) any reductions in Capacity Payments pursuant to Sections 4.1(c) and 4.1(d) with respect to such Contract Year.

(c)      Gulf Power and Shell hereby acknowledge and agree that the terms, conditions and amounts fixed pursuant to Sections 8.7 and 8.8 and Exhibits 8.7 and 8.8 for Availability Payments are reasonable, considering the losses and damages that Gulf Power will sustain in the event the Peak Availability Factor is less than the Peak Availability Target in any Peak Availability Measurement Period or the Off Peak Availability Factor is less than the Off Peak Availability Target in any Off Peak Availability Measurement Period. The amounts of the Availability Payments are agreed upon and fixed by the Parties because of the difficulty of ascertaining the exact amount of losses and damages that will be actually sustained by Gulf Power in any such event. The Parties agree that the Availability Payments are not penalties and shall be applicable regardless of the amount of losses and damages actually sustained by Gulf Power. The payment of any Availability Payments shall not affect Gulf Power’s rights under Sections 11.3 and 11.5(f).

8.10     Energy Imbalance Charges. Shell shall make capacity available and deliver energy from the Plant to Gulf Power at the Energy Point of Delivery. The risk of loss of energy shall pass from Shell to Gulf Power at the Energy Point of Delivery. Gulf Power shall be responsible for and shall pay (or reimburse Shell if Shell has paid) Energy Imbalance Charges only during such periods of time in which the Plant is located within the Southern Control Area. Shell shall not take any action or consent to remove the Plant from the Southern Control Area without Gulf’s written consent. Shell shall be responsible for and shall pay (or reimburse Gulf if Gulf has paid) Energy Imbalance Charges during such periods of time in which the Plant is not located within the Southern Control Area.

8.11     Taxes. (a) As between the Parties, Shell shall indemnify Gulf Power for any material adverse effect on Gulf Power due to any deficiency in the payment of all Taxes on or with respect to the Plant, including its development, permitting, design, engineering, procurement, construction, testing, startup, ownership, leasing, financing, operation, and maintenance. Shell shall pay or cause all Taxes to be paid for (i) the production and delivery of Energy and Ancillary Services to be provided to Gulf Power arising, in the case of Energy, prior to the time of Shell’s delivery of such Energy to Gulf Power at the Energy Point of Delivery, or, in the case of Ancillary Services, prior to the time such Ancillary Services are made available to Gulf Power; (ii) the conversion of Natural Gas into electricity after delivery by Gulf Power and receipt of such Natural Gas at the Primary Gas Delivery Point and (iii) the conversion of Fuel Oil into electricity.

(b) Gulf Power shall pay or cause to be paid all Taxes on or with respect to: (i)

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Energy received by Gulf Power arising at and after the time such Energy is delivered by Shell to the Energy Point of Delivery, (ii) Ancillary Services received by Gulf Power arising at and after the time such Ancillary Services are made available to Gulf Power, (iii) Natural Gas received and possessed by Gulf Power at and prior to the time of delivery of such Natural Gas by Gulf Power to Shell at the Gas Delivery Point, (iv) property taxes on Fuel Oil stored for Gulf Power at the Plant, and (v) the initial sale of Fuel Oil inventory from Shell to Gulf Power. Such Taxes shall include such sales, use, excise or other similar Taxes on the sale to Gulf Power and purchase from Shell of capacity, Energy, and Ancillary Services pursuant to this Agreement. Gulf Power shall be responsible for all Taxes arising out of the transfer and delivery by Gulf Power and receipt of Natural Gas at the Gas Delivery Point, the purchase of Fuel and the initial sale of Fuel Oil inventory from Shell to Gulf Power, and Shell shall be responsible for all Taxes on the sale of Fuel Oil inventory from Gulf Power to Shell at the end of the Operating Term and shall indemnify Gulf Power for any new Taxes that may arise after the date of execution of this Agreement concerning the conversion of Natural Gas or Fuel Oil into Energy; provided, however, that nothing contained in this Section 8.11 shall be construed to affect the applicability of Article 21 to any such new Taxes.

(c)      In the event Shell is required by law or regulation to remit or pay Taxes that are Gulf Power’s responsibility hereunder, Shell may include such Taxes in the next Monthly Invoice and Gulf Power shall remit payment thereof in accordance with Article 9. Conversely, if Gulf Power is required by law or regulation to remit or pay Taxes that are Shell’s responsibility hereunder, Gulf Power may deduct the amount of any such Taxes from the sums otherwise due to Shell under this Agreement. Any refunds associated with such Taxes will be handled in the same manner. Nothing herein shall obligate or cause a Party to pay or be liable to pay any Taxes from which it is exempt under applicable Legal Requirements.

ARTICLE 9

BILLING AND PAYMENT

9.1 Billing. Within twelve days after the end of each Month during the Operating Term, Shell shall deliver to Gulf Power a Statement (in electronic form and in writing) detailing (a) all amounts due from Gulf Power to Shell under this Agreement for the Month, (b) all amounts due from Shell to Gulf Power under this Agreement for the Month, (c) the amount of Delivered Energy during each hour of the Month, with the total Monthly amount to be rounded to the nearest MWh, with .50 MWh being rounded down and .51 MWh being rounded up, (d) the level of Energy expressed in MWh requested by Gulf Power during each hour of the Month, (e) the quantities of Gas and Fuel Oil used by the Plant during each hour of the Month, (f) the number of Starts of each Generating Unit and the calculation of the Start Charge for the Month, (g) the amounts of Energy provided under Section 8.2 and the amounts payable by each Party with respect to such Energy, (h) the Heat Rate Payment due from either Party to the other according to Section 8.3 and the calculation of the Heat Rate Payment, including all applicable Fuel consumption, Daily Gas Index Price and fuel oil cost data, (i) the calculation of any Availability Payments and any Bonus Availability Payments (and all components thereof) for such Month, (j) Cover Payments due from Shell for the Month, and (k) Withholding Payments due from Shell for the Month.

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9.2 Payment. All payments of amounts due under this Agreement shall be made in Dollars by wire transfer in immediately available funds to the respective account of the payee Party set forth in Section 19.9. If Gulf Power and Shell is each required to pay an amount under this Agreement in the same Month, then such amounts with respect to each Party shall be aggregated, and the Parties shall discharge the obligations to pay through netting, in which case the Party owing the greater aggregate amount shall pay to the other Party the difference between the amounts owed. Gulf Power shall pay to Shell the net amount due to Shell, if any, by the later of the 10^th Day after the Statement was received or the 20^th Day of the Month in which the Statement was received. If the Statement shows an amount due from Shell to Gulf Power, Shell shall pay to Gulf Power the amount due by the 20^th Day of the Month following the Month to which the Statement relates. If the payment due date falls on a Day other than a Business Day, the payment will be due on the next Business Day.

9.3 Corrections; Disputes. Billings and payments shall be subject to correction for metering and billing errors for a period of two years after the end of the relevant Month. If either Party disputes the correctness of a Statement, it shall nevertheless pay the undisputed portion of the Statement and shall notify the other Party of the specific basis for disputing the correctness of the Statement, including all supporting calculations, as soon as practicable after becoming aware of the basis for such dispute. Interest on all such amounts in dispute shall accrue at the rate specified in Section 9.4.

9.4 Interest on Past Due Bills. Any payments required to be made under this Agreement that are not paid when due (and any overpayments) shall bear interest, accrued daily from the due date to the date of payment (or from the date of payment until the date of refund in the case of overpayments), at the lesser of (a) the annual rate of five percent plus the Prime Rate as reported in the Money Rates column of The Wall Street Journal on the last Business Day of the preceding Month, as the rate may from time to time change, or (b) the maximum rate of interest permitted by Applicable Law. Notwithstanding the provisions for calculating interest on late payments, a failure to make payment when due shall be a default under this Agreement by the non-paying Party to the extent provided in Sections 11.5 and 11.6.

9.5 Audit Rights. During the Operating Term and for a period of two years after the Termination Date, each Party and any third party representative of a Party shall have the right, at its expense, upon reasonable notice and at reasonable times, to examine the books and records of the other Party to the extent reasonably necessary to verify the accuracy of any Statement, payment demand, charge, payment or computation made under this Agreement. No adjustment or correction shall be made and all records and payments shall be conclusively presumed to be final unless notice specifying the error or inaccuracy is given within 24 Months after the end of the Contract Year during which the error or inaccuracy occurred.

ARTICLE 10

PERFORMANCE SECURITY

10.1     Shell Performance Security. Simultaneous with the execution of this Agreement, Shell shall deliver to Gulf Power, Eligible Collateral in an amount as set forth in Table 10.1(the “Shell Performance Security”). The Shell Performance Security shall be maintained throughout the Term although the amount of Eligible Collateral shall be adjusted from time to time in accordance

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with Table 10.1. Any increases to the amount of Shell Performance Security required shall be delivered by Shell to Gulf Power within one (1) Business Day of the event requiring the increase and any reduction in the amount of Shell Performance Security required by this Section 10.1 shall be delivered by Gulf Power to Shell within one (1) Business Day of Shell’s written request to Gulf Power requesting the reduction in amount of Shell Performance Security.

Table 10.1		Effective Date through May 31, 2013	June 1, 2013-May 31, 2018	June 1, 2019-May 31, 2021	June 1, 2021 – May 31, 2023
Eligible Collateral Amount:		[**]	[**]	[**]	[**]
		Percentage of Eligible Collateral To be Posted based upon Lowest Credit Rating
S&P/Fitch	Moody’s
BBB or above	Baa2 or above	None	None	None	None
BBB-	Baa3	50%	50%	50%	50%
Below BBB-	Below Baa3	100%	100%	100%	100%

In the event that a Material Adverse Change occurs in respect of Shell or Shell’s Guarantor, as applicable, then within one (1) Business Day of such event, Shell shall deliver to Gulf Power Eligible Collateral in an amount equal to 100% of the Eligible Collateral Amount corresponding to the amount shown in Table 10.1 for the date on which such Material Adverse Change occurs; provided, however, that in Gulf Power’s sole discretion, based on a review of the overall circumstances of Shell’s Material Adverse Change, the Eligible Collateral that Shell is required to provide may be reduced to an amount below that stated in Table 10.1. Within (1) Business Day of the occurrence of such Material Adverse Change and a Ratings Agency has publicly confirmed or revised Shell or Shell’s Guarantor’s senior unsecured debt or issuers rating as applicable, the Eligible Collateral amount shall be adjusted to maintain consistency with Table 10.1.

10.2     Gulf Power Performance Security. Simultaneous with the execution of this Agreement, Gulf Power shall deliver to Shell, Eligible Collateral in an amount as set forth in Table 10.1 above(the “Gulf Power Performance Security”). The Gulf Power Performance Security shall be maintained throughout the Term although the amount of Eligible Collateral shall be adjusted from time to time in accordance with Table 10.1. Any increases to the amount of Gulf Power Performance Security required shall be delivered by Gulf Power to Shell within one (1) Business Day of the event requiring the increase and any reduction in the amount of Gulf Power Performance Security required by this Section 10.2 shall be delivered by Shell to Gulf Power within one (1)

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Business Day of Gulf Power’s written request to Shell requesting the reduction in amount of Gulf Power Performance Security. In the event that a Material Adverse Change occurs in respect of Gulf Power or Gulf Power’s Guarantor, as applicable, then within one (1) Business Day of such event, Gulf Power shall deliver to Shell Eligible Collateral in an amount equal to 100% of the Eligible Collateral Amount corresponding to the amount shown in Table 10.1 for the date on which such Material Adverse Change occurs; provided, however, that in Shell’s sole discretion, based on a review of the overall circumstances of Gulf Power’s Material Adverse Change, the Eligible Collateral that Gulf Power is required to provide may be reduced to an amount below that stated in Table 10.1. Within (1) Business Day of the occurrence of a Material Adverse Change and a Ratings Agency has publicly confirmed or revised Gulf Power or Gulf Power’s Guarantor’s senior unsecured debt or issuers rating as applicable, the Eligible Collateral amount shall be adjusted to maintain consistency with Table 10.1.

10.3     Replacement Collateral; Substituted Collateral; Release of Collateral. (a) To the extent that any replacement of Shell Performance Security or Gulf Power Performance Security is required to maintain compliance with Section 10.1 or 10.2, the Party responsible for posting any such replacement Eligible Collateral shall deliver same to the beneficiary Party within two (2) Business Days after such replacement is required.

(b)      Upon any reduction of the amount of the Shell Performance Security or Gulf Power Performance Security pursuant to Section 10.1 or 10.2, the beneficiary thereof shall, upon written request by the other Party, release within two (2) Business Days any Eligible Collateral that is no longer required. The choice of any Eligible Collateral provided by a Party may be selected from time to time by such Party, and upon receipt of substitute Eligible Collateral, the holder of the Eligible Collateral for which substitution is being made shall promptly release such Eligible Collateral in an amount equal to that which is being substituted. Following any termination of this Agreement, the Parties shall mutually agree to a final settlement of all obligations under this Agreement, which such period shall not exceed six (6) Months from such termination date, and after such settlement, any remaining Eligible Collateral posted by a Party that has not been drawn upon by the other Party pursuant to its rights under this Agreement shall be returned promptly to such Party. Any dispute between the Parties regarding such final settlement shall be resolved according to the applicable procedures set forth in Article 16.

10.4     Draws; Replenishment. A Non-Defaulting Party may draw upon the Eligible Collateral provided by the other Party following the occurrence of a Default by such other Party or pursuant to the other provisions of this Agreement in order to recover any damages to which such Non-Defaulting Party is entitled to under this Agreement. In the event of such a draw on the Eligible Collateral, then, except in the circumstance when the Non-Defaulting Party terminates this Agreement, the Defaulting Party shall replenish within two (2) Business Days the Eligible Collateral to the full amount required by Sections 10.1 or 10.2, as applicable.

10.5     Reporting. (a) Shell shall promptly notify Gulf Power of any circumstance that results in Shell’s failure to be in compliance with the Shell Performance Security requirements of this Article 10. From time to time, at Gulf Power’s written request, Shell shall provide Gulf Power with such evidence as Gulf Power may reasonably request that Shell and any Shell Guarantor, Shell Guaranty, Letter of Credit or Security Account is in full compliance with this Agreement.

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(b)      Gulf Power shall promptly notify Shell of any circumstance that results in Gulf Power’s failure to be in compliance with the Gulf Power Performance Security requirements of this Article 10. From time to time, at Shell’s written request, Gulf Power shall provide Shell with such evidence as Shell may reasonably request that Gulf Power and any Gulf Power Guarantor, Gulf Power Guaranty, Letter of Credit or Security Account is in full compliance with this Agreement.

ARTICLE 11

TERM, TERMINATION AND DEFAULTS

11.1     Term. This Agreement shall become effective on the Effective Date and shall continue in effect until the Termination Date. The provisions of Articles 13, 15 and 19 and Sections 16.1 and 16.2 shall survive the termination of this Agreement, provided that the provisions of Article 15 shall not extend beyond five years following the Termination Date.

11.2     Remedies. If any Default described in Section 11.5 or 11.6 is not cured within the applicable period, if any, set forth in Section 11.5 or 11.6, then the non-defaulting Party (the “Non-Defaulting Party”) may, for so long as the Default is continuing, subject to the provisions of Article 20, take one or more of the following actions: (i) establish a date (which date shall be no more than ten (10) Business Days after the Non-Defaulting Party delivers written notice of such date to the defaulting Party (the “Defaulting Party”)) on which this Agreement shall terminate (the “Early Termination Date”), and (ii) immediately cease performance or withhold any payments, or both, due in respect of this Agreement.

11.3     Termination for Default. If an Early Termination Date has been established, the Non-Defaulting Party shall in good faith calculate its Gains, Losses and Costs resulting from the termination of this Agreement, aggregate such Gains, Losses and Costs into a single net amount (the “Termination Payment”), and then notify the Defaulting Party. The Gains, Losses and Costs shall be determined by comparing the cost under this Agreement of the capacity and Energy that would be available under this Agreement for the remainder of the Operating Term had this Agreement not been terminated to the market price of capacity and Energy of equivalent reliability and scheduling flexibility for the remaining Operating Term (had this Agreement not been terminated) reasonably determined utilizing the most cost effective option available. To ascertain such market price, the Non-Defaulting Party may consider, among other evidence, the settlement prices of NYMEX energy futures contracts, quotations from leading dealers in energy and gas swap contracts, offers for replacement capacity and Energy or bids to purchase the remaining capacity and Energy that was to be sold pursuant to this Agreement, in either case made by bona fide third-parties (including offers received by the Non-Defaulting Party in response to any request for proposals for capacity and energy contracts), reasonable necessary differences in locational basis (including costs associated with transmission service, reliability, scheduling flexibility, additional investments costs, if any required, less any benefits received or retained) and any other similar considerations affecting value, all adjusted for the length of the remaining Operating Term (had this Agreement not been terminated). Neither Party shall be required to enter into replacement transactions in order to determine the Termination Payment. If the Non-Defaulting Party’s aggregate Losses and Costs exceed its aggregate Gains, the Defaulting Party shall, unless it disagrees with such Termination Payment calculation, within fifteen (15) Business Days of receipt of such notice, pay the net amount to the Non-Defaulting Party, which amount shall bear interest at the interest rate specified in Section

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9.4 from the Early Termination Date until paid. If the Non-Defaulting Party’s aggregate Gains exceed its aggregate Losses and Costs, if any, resulting from the termination of this Agreement, the Non-Defaulting Party may retain such Gains. If the Defaulting Party disagrees with the calculation of the Termination Payment, the issue shall be resolved pursuant to the provisions of Article 16 applicable to Termination Payment disputes, and the resulting Termination Payment shall be due and payable within three (3) Business Days after the award. As used in this Section 11.3 (i) “Costs” shall mean, brokerage fees, commissions and other similar transaction costs and expenses reasonably incurred by such Party either in terminating any agreement which it has entered into to fulfill its obligations hereunder or entering into new agreements which replace this Agreement, and attorneys’ fees, if any, incurred in connection with enforcing its rights under this Agreement; (ii) “Gains” shall mean, an amount equal to the economic benefit determined on a mark to market basis (exclusive of Costs), if any, to the Non-Defaulting Party resulting from the termination of this Agreement; and (iii) “Losses” shall mean an amount equal to the economic loss determined on a mark to market basis (exclusive of Costs), if any, to the Non-Defaulting Party resulting from the termination of this Agreement. For the avoidance of doubt, nothing in Article 10 is intended to limit liability under this Section 11.3.

11.4     Winding Up Arrangements. Within 45 Days after the Termination Date, any amounts due from either Party shall be paid, any corrections or adjustments to payments previously made shall be determined, and any refunds made. The obligations of the Parties under this Agreement shall remain in effect for the purpose of complying with this Section 11.4. All indemnity and confidentiality obligations, audit rights, and other provisions specifically providing for survival shall survive the termination of this Agreement. The termination of this Agreement shall not relieve either Party of (a) any unfulfilled obligation or undischarged liability of such Party on the Termination Date, or (b) the consequences of any breach or default of any warranty or covenant in this Agreement. All obligations and liabilities described in the preceding sentence, and applicable provisions of this Agreement creating or relating to such obligations and liabilities, shall survive the Termination Date.

11.5     Shell Defaults. The following events shall constitute defaults of Shell under this Agreement:

(a) Shell shall:

(i) file a petition or otherwise commence, or authorize or acquiesce in the commencement of, a proceeding or cause under any bankruptcy, insolvency, receivership or similar law for the protection of creditors or have such petition filed or proceeding commenced against it, which in the case of an involuntary petition or proceeding remains undismissed for a period of 90 Days; or

(ii) assign this Agreement or transfer any assets in violation of Article 17;

(b) the failure by Shell to cause Owner to maintain insurance as required by

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Section 18.3(c), and such failure is not cured within fifteen Days after written notice of such failure is given to Shell by Gulf Power;

(c) the failure by Shell to make when due any payment (other than amounts disputed in good faith) required under this Agreement if such failure is not remedied within 30 Days after written notice of such failure is given to Shell by Gulf Power or the failure of Shell to pay any amount within five Days following the determination under Article 16 that such amount is due;

(d) (i) the continuation by Shell of any intentional practice of withholding Energy following a determination under Article 16 that (A) such practice was not in accordance with and part of Shell’s good faith employment of Prudent Generator Practices and (B) such practice was not otherwise permitted by the express terms of this Agreement; or (ii) the continued, material failure by Shell to provide information required to be delivered to Gulf Power under Section 12.4 following a determination under Article 16 that such information (or information of the same specific type) is required to be delivered under Section 12.4;

(e) the failure by Shell to perform any material obligation under this Agreement (other than an obligation to make payment or obligations that are otherwise specifically set forth in this Section 11.5 as a separate default), and such failure is not cured within 70 Days after written notice of such failure (setting forth in reasonable detail the grounds on which Gulf Power is asserting such failure) is given to Shell by Gulf Power or, if such failure by its nature cannot reasonably be cured within 70 Days, such longer period (not to exceed 180 Days after such written notice) as is reasonably necessary to cure such failure and during which Shell is using diligent efforts to cure; provided that if there is a good faith dispute between the Parties as to whether a default has occurred under this Section 11.5(e), Shell shall not be considered to be in default under this Section 11.5(e) until such failure continues for a period of ten Days after the failure is determined under Article 16 to be a default;

(f)  the Peak Availability Percentage is less than [**]% in any three Contract Years within a period of five consecutive Contract Years, or the Off Peak Availability Percentage is less than [**]% in any three Contract Years within a period of five consecutive Contract Years;

(g) the Contract Capacity is less than [**] MW for any 30 Months within a period of five consecutive Contract Years or for any 18 consecutive Months;

(h) the Contract Capacity is less than [**] MW for any 36 Months within a period of five consecutive Contract Years;

(i)  termination or cancellation of the Energy Interconnection Agreement unless such termination or cancellation was caused by Gulf Power, if such Energy Interconnection Agreement is not reinstated on the same terms and such agreement is not replaced by an interconnection agreement or other arrangements for interconnection reasonably satisfactory to Gulf Power within 200 Days after its termination or cancellation. For purposes of this Section 11.5(i), a replacement interconnection agreement or arrangement will be considered to be satisfactory to Gulf Power if such agreement or arrangement is no less favorable to Gulf Power

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and Owner (to the extent the rights and obligations of Owner thereunder could reasonably be expected to affect Gulf Power and/or its ability to receive capacity, Energy and Ancillary Services from the Plant) than the interconnection agreements or arrangements that are generally available to electric generators in the region at the relevant time; Shell shall have the right to extend such 200-Day period by up to an additional 180 Days upon demonstrating that it is using diligent efforts, including in proceedings before appropriate regulatory bodies, to replace such agreement; provided, however, that during such initial 200-Day period (as it may be extended), Gulf Power’s obligations under this Agreement shall be suspended to the extent that the termination or cancellation of the Energy Interconnection Agreement limits the ability to deliver and transmit Energy in an amount reflecting the Plant Capability into SERC;

(j)  abandonment of the Plant by Owner, and such abandonment continues for 30 Days after written notice thereof is given to Shell by Gulf Power;

(k) Shell or Owner repudiates or rescinds the Tenaska ECA, or the Tenaska ECA Agreement is otherwise terminated, unless the Tenaska ECA is reinstated on the same terms or replaced by an energy conversion agreement or other arrangements for energy conversion services reasonably satisfactory to Gulf Power within 30 Days; or

(l)  the failure by Shell to comply with the Performance Security requirements under Article 10, if such failure is not remedied within 2 Business Days after written notice of such failure is given to Shell by Gulf Power.

11.6     Gulf Power Defaults. The following events shall constitute defaults of Gulf Power under this Agreement:

(a) the failure by Gulf Power to make when due any payment (other than amounts disputed in good faith) required under this Agreement if such failure is not remedied within 30 Days after written notice of such failure is given to Gulf Power by Shell; or

(b) the failure by Gulf Power to comply with the Performance Security requirements under Article 10, if such failure is not remedied within 2 Business Days after written notice of such failure is given to Gulf Power by Shell.

11.7     Set-off. Each Party reserves to itself all rights of set-off, counterclaim, and other remedies and/or defenses, except to the extent excluded by Section 13.7, which such Party is or may be entitled to assert arising from or out of this Agreement.

ARTICLE 12

RECORDS; ACCESS TO PLANT AND INFORMATION

12.1     Records. Shell shall cause Owner to maintain an accurate and up-to-date operating log at the Plant with records of real and reactive power production for each hour, changes in operating status, Scheduled Outages and Forced Outages and any unusual conditions found during inspections. The operating log shall be maintained in sufficient detail to allow Gulf Power to determine the Energy generated during each hour, including records of the average ambient air

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temperature at the Plant during each hour. Gulf Power shall be permitted to inspect such operating log upon request and copies of such log shall be provided, if requested, within 35 Days of Gulf Power’s request. Shell shall cause Owner to retain these records for a period of at least four years after the logs were created.

12.2     Access to Plant. Gulf Power and its representatives shall at all times before and during the Operating Term have access to the Plant and the Plant Site upon 48 hours’ prior notice to Shell for purposes of (a) observing and inspecting the Plant and the operation and maintenance of the Plant, and (b) performing all acts related to delivery of Fuel to the Plant; provided that Gulf Power and its representatives shall not unreasonably interfere with the operation and maintenance of the Plant and shall follow the safety and security rules applicable to the Plant Site.

12.3 [Intentionally Omitted]

12.4     Monthly Operating Reports. No later than the last Day of each Month during the Operating Term, Shell shall send to Gulf Power an operating report for the preceding Month. The operating report shall contain (a) a summary of information from the operating log, (b) a report of any Unscheduled Outages greater than 24 hours and a description of the steps being taken or to be taken to avoid similar Unscheduled Outages, and (c) a general description of any and all operating and maintenance problems or abnormalities experienced and the steps being taken or to be taken to remedy the problems or abnormalities.

ARTICLE 13

INDEMNITIES; LIMITATION ON DAMAGES

13.1     Indemnity for the Parties’ Personnel and Property. (a) Gulf Power releases and shall defend, indemnify and hold harmless Shell and its Related Parties and Owner and its Related Parties from and against all Claims relating to this Agreement for illness, injury and death of Gulf Power’s personnel and for damage to and loss of Gulf Power’s property.

(b) Shell releases and shall defend, indemnify and hold harmless Gulf Power and its Related Parties from and against all Claims relating to this Agreement for illness, injury and death of Shell’s personnel and for damage to and loss of Shell’s property.

13.2     Indemnity for Ownership and Operation of the Plant. Shell releases and shall defend, indemnify and hold harmless Gulf Power and its Related Parties from and against all Claims against Gulf Power and its Related Parties arising directly or indirectly from the operation and maintenance of the Plant, except for Claims arising proximately from the negligence or other wrongful conduct of Gulf Power or its Related Parties or from Gulf Power’s or Gulf Power’s Related Parties’ contractual relationships with Persons other than Shell.

13.3     Indemnities for Fuel. Gulf Power and Shell each releases and shall defend, indemnify and hold harmless the other and its respective Related Parties (and Gulf Power shall defend, indemnify and hold harmless Owner and its Related Parties) from and against all Claims sustained by the party entitled to indemnification arising out of or relating to any act or incident occurring when exclusive control and possession of Fuel delivered under this Agreement is vested in

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the indemnifying Party. In addition, Gulf Power agrees to indemnify and hold Shell and its Related Parties and Owner and its Related Parties harmless from and against any and all Claims of whatsoever nature relating to the title to Gas delivered by Gulf Power under this Agreement or relating to the wrongful payment of or failure to pay an owner of an interest in such Gas.

13.4     Indemnity for Energy. Gulf Power and Shell each releases and shall defend, indemnify and hold harmless the other and its respective Related Parties (and Gulf Power shall defend, indemnify and hold harmless Owner and its Related Parties) from and against all Claims relating to capacity, Energy and Ancillary Services delivered or requested to be delivered under this Agreement and arising on its respective side of the Energy Point of Delivery.

13.5     SCOPE OF INDEMNITY; WAIVER OF SUBROGATION. IT IS THE PARTIES’ INTENT THAT, EXCEPT AS PROVIDED IN SECTION 13.2, THE INDEMNITY OBLIGATIONS IN THIS AGREEMENT ARE WITHOUT REGARD TO THE CAUSES OF INDEMNIFIED CLAIMS, INCLUDING THE NEGLIGENCE OF ANY INDEMNIFIED PARTY, WHETHER SUCH NEGLIGENCE IS SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE OR THE STRICT LIABILITY OF ANY INDEMNIFIED PARTY. Gulf Power and Shell shall each cause its respective insurers to waive all express and implied rights of subrogation against the other Party and the Related Parties of such other Party to the extent and scope of liabilities assumed under this Agreement.

13.6     Indemnity Procedure. The indemnified Party shall promptly notify the indemnifying Party in writing of any Claim and the indemnifying Party shall have the right to assume the investigation and defense of the Claim, including employing legal counsel. If the indemnifying Party does not within thirty (30) days assume the investigation and defense of the Claim, the indemnified Party may do so, including employing legal counsel of its choice, at the indemnifying Party’s expense. In any case, the indemnifying Party shall pay or reimburse the indemnified Party for all court costs, attorneys’ fees and experts’ fees relating to the Claim and post any appeals bonds. If the indemnifying Party assumes the defense of a Claim, the indemnified Party has the right to employ at its expense separate legal counsel and participate in the defense of the Claim. The indemnifying Party shall not be liable for any settlement of a Claim without its written consent to the settlement. To prevent double recovery for a Claim, the indemnified Party shall reimburse the indemnifying Party for payments or costs incurred in an indemnity Claim with the proceeds of any judgment, insurance, bond, surety or other recovery by the indemnified Party for the indemnified Claim.

13.7     LIMITATION ON DAMAGES. THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, THE OBLIGOR’S LIABILITY SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY HEREIN PROVIDED, THE OBLIGOR’S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED.

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UNLESS EXPRESSLY HEREIN PROVIDED, AND EXCEPT FOR THE PAYMENT OF LIQUIDATED DAMAGES SPECIFIED HEREIN, NEITHER PARTY NOR THEIR AFFILIATES SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE ACTUAL DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE LIQUIDATED DAMAGES DO NOT CONSTITUTE A PENALTY AND ARE A REASONABLE APPROXIMATION OF THE HARM OR LOSS. NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS AGREEMENT, IN NO EVENT SHALL GULF POWER’S LIABILITY TO SELLER FOR A TERMINATION PAYMENT UNDER THIS AGREEMENT EXCEED AN AMOUNT EQUAL TO THE SUM OF ANY AMOUNTS THEN OWED BY GULF POWER HEREUNDER PLUS THE TOTAL OF ALL REMAINING MONTHLY CAPACITY PAYMENTS FOLLOWING TERMINATION THAT WOULD HAVE BEEN PAYABLE TO SHELL UNDER THIS AGREEMENT HAD THE AGREEMENT REMAINED IN EFFECT THROUGH MAY 24, 2023.

13.8     Economic Adjustments. Shell’s failure to achieve the Peak Availability Target or the Off Peak Availability Target shall result in the payments expressly provided in this Agreement but, without limiting the effect of Sections 11.5(d), 11.5(f), 11.5(g), 11.5(h), 11.5(i), and 11.5(j), shall not constitute a breach of this Agreement.

ARTICLE 14

FORCE MAJEURE

14.1     Burden of Proof. The burden of proof as to whether a Force Majeure event has occurred shall be upon the Party claiming Force Majeure.

14.2     Suspension of Obligations. Except as otherwise provided in Section 14.3(g), if either Party is unable, wholly or in part, to perform its obligations under this Agreement because of a Force Majeure event, that Party will be excused from whatever performance is affected by the Force Majeure event to the extent so affected from the inception and during the continuance of any such Force Majeure. The suspension of performance shall be of no greater scope and of no longer duration than is reasonably required by the Force Majeure event. Notwithstanding the foregoing, the occurrence of a Force Majeure event shall not affect the provisions of Section 11.5(f), (g) or (h).

14.3     Notice of Force Majeure Event. (a) The Party claiming Force Majeure shall give notice to the other Party as soon as possible (but in any event within two Days) after becoming aware of the occurrence of a Force Majeure event. The notice shall describe the particulars of the occurrence, including an estimate of its expected duration and probable impact on the performance of such Party’s obligations under this Agreement. During the continuation of the Force Majeure event, the Party claiming Force Majeure shall continue to furnish timely regular reports with respect to the event.

(b) No liability of either Party for an event that arose before the occurrence of the

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Force Majeure event shall be excused as a result of the occurrence.

(c) The non-performing Party shall exercise all reasonable efforts to mitigate or limit damages to the other Party.

(d) The non-performing Party shall promptly correct the Force Majeure event or condition to the extent it may be corrected through the exercise of diligent efforts.

(e) When the non-performing Party is able to resume performance of its obligations under this Agreement, that Party shall give the other Party written notice to that effect and shall promptly resume performance.

(f)  The term of this Agreement shall not be extended beyond its normal expiration date by any period of time during which performance is suspended due to Force Majeure.

(g) The occurrence of a Force Majeure event shall not relieve a Party’s obligation to pay money, Gulf Power’s obligation to make Capacity Payments, or Shell’s obligation to make Availability Payments and shall not in any way affect the operation of Section 4.1. For further clarity, a Force Majeure event shall not prevent Gulf Power from making a Request for Energy to the extent that such request would be permitted herein absent an event of Force Majeure or relieve Shell’s obligation (a) to deliver Energy pursuant to such Request for Energy, (b) calculate or make Availability Payments during the continuance of a Force Majeure event or (c) implement the provision of Section 5.7, if elected by Shell.

ARTICLE 15

CONFIDENTIALITY

15.1     Scope. Each Party shall keep Confidential (a) this Agreement, (b) all negotiations concerning this Agreement, and (c) all documents, data, drawings, studies, projections, plans and other information, whether written or oral, which relate to economic benefits to or amounts payable by either Party pursuant to this Agreement or costs of operations of the Plant, including cost of fuel (items (a) through (c) are hereafter referred to as “Confidential Information”).

15.2     Exceptions. Either Party may, without violating this Article, disclose Confidential Information:

(a)      to such Party’s Affiliates, consultants, advisors, lenders, financiers, credit rating agencies, contractors, suppliers or to Owner or others involved in operation and maintenance of the Plant, provided that the Party making the disclosure obtains, as a condition precedent to the disclosure, a confidentiality agreement with the Person to whom the disclosure is being made (other than Affiliates, attorneys, accountants and full-time individual consultants) providing substantially the same assurance of maintaining confidentiality as the provisions of this Article, provided, further, that the disclosure shall not include any information relating to transactions downstream of the Energy Point of Delivery;

(b)      in public filings with the FPSC, the Securities and Exchange Commission and other governmental officials and parties involved in any proceeding whereby either Party is seeking a

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permit, certificate or other regulatory approval or order necessary or appropriate to carry out this Agreement; provided that the Party making the disclosure will exercise reasonable efforts to restrict public access of the information disclosed by way of protective order or otherwise; and

(c)      to governmental officials or the public as required by any Applicable Law, including Applicable Laws requiring disclosure of financial information, information material to financial matters and filing of financial reports; provided, that the Party making the disclosure will exercise reasonable efforts to restrict public access to the information disclosed by way of protective order or otherwise.

15.3     Certain Limitations and Public Announcements.  (a) The timing and content of all public announcements relating to the execution of this Agreement and the consummation of the transactions contemplated hereby shall be subject to approval by both Gulf Power and Shell prior to the release of such public announcements, and each Party agrees to cooperate with the other Party as appropriate to comply with all Applicable Laws with respect to public disclosures.

ARTICLE 16

RESOLUTION OF DISAGREEMENTS

16.1     Disagreements. Each Party shall appoint a representative who shall be responsible for administering this Agreement on behalf of such Party and for representing the Party’s interests in disagreements. Any disagreement between the Parties relating to this Agreement that is not resolved between the Parties’ representatives shall be referred by the Parties’ representatives in writing to the senior management of the Parties for resolution. The senior management of the Parties shall then have ten Days in which to resolve the disagreement.

16.2     Arbitration. Disagreements under, relating to or touching upon this Agreement that are not resolved by the procedure set forth in Section 16.1 shall be referred to and determined in a binding arbitration by a single arbitrator appointed by the Parties according to the commercial arbitration rules of the Arbitration Body, subject to the following:

(a)      Arbitration proceedings shall be commenced by one Party delivering notice to the other Party demanding arbitration and may be commenced either before, during or after the ten-Day period set forth in Section 16.1. Upon the delivery of notice demanding arbitration, the Parties shall jointly, within 15 Days, choose an arbitrator.

(b)      If the Parties do not choose an arbitrator within the 15-Day period, then either Party may request that the arbitrator be chosen according to the Arbitration Body’s expedited commercial arbitration rules. The arbitrator must not have been previously employed by either Party and must not have a direct or indirect interest in either Party or the subject matter of the arbitration.

(c)      Arbitration hearings shall be held in alternating locations at the home offices of Gulf Power and Shell, commencing with Gulf Power’s office.

(d)      Within seven Days after the arbitrator is chosen, each Party shall independently present to the arbitrator a proposal with supporting rationale for resolving the disagreement. The arbitrator shall proceed immediately to hear the matter. Except as provided in this Section 16.2, the

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arbitration shall be governed and administered exclusively by the Arbitration Body according to the commercial arbitration rules of the Arbitration Body.

(e)      The arbitrator shall order the Parties to promptly exchange copies of all exhibits and witness lists and, if requested by a Party, to produce other relevant documents, to answer up to ten interrogatories (including subparts), to respond to up to ten requests for admissions (which shall be deemed admitted if not denied) and to produce for deposition and, if requested, at the hearing, all witnesses that such Party has listed and up to four other persons within such Party’s control. Any additional discovery shall only occur by agreement of the Parties or as ordered by the arbitrator upon a finding of good cause.

(f)      The arbitrator shall have the power to grant a declaratory judgment and, in order to prevent irreparable harm, the arbitrator shall have the power to grant temporary or permanent injunctive or other equitable relief. Prior to the appointment of the arbitrator a Party may, notwithstanding any other provision of this Agreement, seek temporary injunctive relief from any court of competent jurisdiction; provided that the Party seeking such relief shall (if arbitration has not already been commenced) simultaneously commence arbitration. Such court-ordered relief shall not continue more than ten Days after the appointment of the arbitrator (or in any event for longer than 60 Days).

(g)      The award of the arbitrator must be made within 30 Days after his or her appointment, subject to any reasonable delay due to unforeseen circumstances. If the arbitrator does not make a decision within 30 Days after his or her appointment, the Parties shall select a new arbitrator in like manner as if none had previously been selected. The award of the arbitrator shall indicate which Party is the Prevailing Party, as defined in Section 16.2(i).

(h)      The decision of the arbitrator must be in writing and signed by the arbitrator and shall be final and binding on the Parties, and the Parties must abide by and perform according to the terms and conditions of the decision. Judgment upon the award rendered by the arbitrator may be entered by any court having jurisdiction.

(i)       During the course of the arbitration, each Party shall pay one-half of the fees and expenses of the arbitrator and the arbitration process, and each Party shall pay its own expenses of the arbitration; provided that if court proceedings to stay litigation or compel arbitration are necessary, the Party who unsuccessfully opposes such proceedings shall pay all reasonable associated costs, expenses and attorneys fees in connection with such court proceedings. If the arbitration results in a final adjudication, determination, or award primarily in favor of either Party (the “Prevailing Party”), the other Party shall, within five Days after demand by the Prevailing Party, reimburse the Prevailing Party for all of the Prevailing Party’s costs in connection with the arbitration, including legal fees and costs and the costs of the arbitration.

16.3     No Challenge; Defense of Agreement. Excluding all matters involving a contractual dispute between the Parties:

(a)      neither Party shall directly or indirectly challenge the equity, fairness, reasonableness or lawfulness of any terms or conditions set forth in or established according to this

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Agreement, as those terms or conditions may be at issue before any Governmental Authority, if the successful result of such challenge would be to preclude or excuse the performance of this Agreement by either Party; and

(b)      each Party shall support and defend this Agreement before any Governmental Authority, if the substance, validity or enforceability of all or any part of this Agreement is challenged or if any proposed changes in regulatory practices or procedures would have the effect of making this Agreement invalid or unenforceable or would subject either Party to any greater or different regulation or jurisdiction that materially affects the rights or obligations of the Parties under this Agreement.

16.4     Continued Performance. The Parties shall continue to perform their respective obligations under this Agreement during the pendency of any dispute, including a dispute regarding the effectiveness or the purported termination of this Agreement.

16.5     Consolidation. Gulf Power hereby consents to the joinder or consolidation of any arbitration hereunder with any arbitration between Shell and Owner under the Tenaska ECA that involves any common issue of law or material fact. Shell shall endeavor to cause Owner to consent to such joinder or consolidation and shall cooperate with Gulf Power regarding any claims against Owner in which Shell and Gulf Power have a common interest.

ARTICLE 17

ASSIGNMENT

17.1     Restriction on Assignment. This Agreement shall be binding upon and inure to the benefit of the successors, assigns and legal representatives of the Parties. Except as provided in Sections 17.2 and 17.3, neither Party may assign this Agreement or any right or obligation under this Agreement without the prior written consent of the other Party, which consent shall not be unreasonably withheld. Except for transfers according to Section 17.2, no transfer or assignment permitted or consented to according to this Article 17 shall relieve the transferring Party of responsibility or liability for any obligation or liability under this Agreement. Any purported assignment in contravention of this Section 17.1 shall be void.

17.2     Exception for Transfers to Affiliates. Notwithstanding Section 17.1, Either Party has the right, without the consent of the other Party, to assign this Agreement, in whole or in part, to an Affiliate, provided that in any such case (i) the assignee shall assume the obligations of the assigning Party under this Agreement and (ii) any performance assurance required under Article 10 shall remain in place.

17.3     Exception for Financing. Notwithstanding Section 17.1, Shell may, without Gulf Power’s consent, collaterally assign its rights under this Agreement as security for indebtedness. If Shell collaterally assigns its rights under this Agreement, Gulf Power shall, upon Shell’s request, deliver to Shell an opinion of counsel and a consent and agreement in a form and substance reasonably requested by Shell.

ARTICLE 18

REPRESENTATIONS AND WARRANTIES; COVENANTS

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18.1     Gulf Power’s Representations and Warranties. As a principal cause and material inducement to Shell to enter into this Agreement, Gulf Power represents and warrants to Shell as follows:

(a)      Gulf Power hereby warrants title and the right to sell all of the Gas to be delivered by Gulf Power hereunder from time to time, and that said Gas shall be free from all adverse claims, including without limitation, royalty and other interest owners’ claims.

(b)      Gulf Power is a corporation duly formed, currently existing and in good standing under the laws of the State of Florida. Gulf Power is duly qualified and authorized to conduct business in every jurisdiction in which the nature of its business requires it to be so qualified. Gulf Power has all requisite power and authority to carry on its business as now conducted, including the execution and performance of this Agreement.

(c)      The execution, delivery and performance by Gulf Power of this Agreement have been duly authorized by all necessary corporate action on the part of Gulf Power and do not require any approval or consent of any holder (or any trustee for any holder) of any indebtedness or other contractual obligation of Gulf Power, or any other Person, except approvals or consents which have previously been obtained.

(d)      This Agreement is in full force and effect, has been duly executed and delivered on behalf of, and by the appropriate officers or agents of, Gulf Power, and, subject to the requirement for regulatory approval of the FPSC consistent with Article 20, constitutes the legal, valid and binding obligation of Gulf Power, enforceable against it in accordance with its terms except as the enforceability thereof may be limited by (a) bankruptcy, insolvency, reorganization or other similar laws affecting the enforcement of creditors’ rights generally and (b) general principles of equity whether considered in a proceeding in equity or at law.

(e)      Other than the requirement for regulatory approval of the FPSC consistent with Article 20, there is no litigation, action, suit, proceeding or investigation by any third party pending or, to the knowledge of Gulf Power, after due inquiry, threatened against Gulf Power before or by any court, administrative agency, arbitrator or governmental authority, body or agency which, if adversely determined, individually or in the aggregate, (i) could be reasonably expected to affect adversely the performance by Gulf Power of its obligations hereunder, or which could be reasonably expected to modify or otherwise affect adversely any authorizations to enable Gulf Power to perform its respective obligations under this Agreement, (ii) could be reasonably expected to have a material adverse effect on the condition (financial or otherwise), business or operations of Gulf Power, or (iii) could reasonably be expected to impair the validity, binding effect or enforceability hereof against Gulf Power or of any action taken or to be taken pursuant hereto or any of the transactions contemplated hereby.

(f)      The execution, delivery and performance by Gulf Power of this Agreement and the consummation of the transactions contemplated hereby will not result in any violation of, breach of or default under any term of (i) Gulf Power’s organizational documents, (ii) any contract or agreement to which Gulf Power is a party or by which it is bound, or (iii) any license, permit, franchise, judgment, writ, injunction, decree, order, charter, law, ordinance, rule or regulation

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applicable to Gulf Power, except for any such violations, breaches or defaults which, individually or in the aggregate, would not adversely affect the performance by Gulf Power of its obligations under this Agreement.

(g)      Other than the requirement for regulatory approval of the FPSC consistent with Article 20, no consent, order, authorization, waiver, approval or any other action, or registration, declaration or filing with, any Person, board or body, public or private, is required to be obtained by Gulf Power in connection with the execution, delivery or performance of this Agreement or the consummation of the transactions contemplated hereunder.

18.2     Shell’s Representations and Warranties. As a principal cause and material inducement to Gulf Power to enter into this Agreement, Shell hereby represents and warrants to Gulf Power as follows:

(a)      Shell is a limited partnership duly organized, validly existing and in good standing under the laws of the State of Delaware. Shell is duly qualified, authorized to do business and in good standing in every jurisdiction in which the nature of its business requires it to be so qualified, and has all requisite power and authority, partnership and otherwise, to enter into and to perform its obligations hereunder, and to carry out the terms hereof and the transactions contemplated hereby.

(b)      The execution, delivery and performance by Shell of this Agreement have been duly authorized by all necessary partnership action on the part of Shell and do not require any approval or consent of any holder (or any trustee for any holder) of any indebtedness or other contractual obligation of Shell or any other Person, except approvals or consents which have previously been obtained.

(c)      This Agreement is in full force and effect, has been duly executed and delivered on behalf of, and by the appropriate officers or agents of, Shell, and constitutes the legal, valid and binding obligation of Shell, enforceable against it in accordance with its terms except as the enforceability thereof may be limited by (a) bankruptcy, insolvency, reorganization or other similar laws affecting the enforcement of creditors’ rights generally and (b) general principles of equity whether considered in a proceeding in equity or at law.

(d)      There is no litigation, action, suit, proceeding or investigation by any third party pending or, to Shell’s knowledge after due inquiry, threatened against Shell before or by any court, administrative agency, arbitrator or governmental authority, body or agency which, if adversely determined, individually or in the aggregate, (i) could be reasonably expected to affect adversely the performance by Shell of its obligations hereunder, or which could be reasonably expected to modify or otherwise affect adversely the authorizations to enable Shell to perform this Agreement, (ii) could be reasonably expected to have a material adverse effect on the condition (financial or otherwise), business or operations of Shell, or (iii) could be reasonably expected to impair the validity, binding effect or enforceability hereof against Shell or of any action taken or to be taken pursuant hereto or any of the transactions contemplated hereby.

(e) The execution, delivery and performance by Shell of this Agreement and the

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consummation of the transactions contemplated hereby will not result in any violation of, breach of or default under any term of (i)  Shell’s organizational documents, (ii) any contract or agreement to which Shell is a party or by which it is bound, or (iii) any license, permit, franchise, judgment, writ, injunction, decree, order, charter, law, ordinance, rule or regulation applicable to Shell, except for any such violations, breaches or defaults which, individually or in the aggregate, would not adversely affect the performance by Shell of its obligations under this Agreement.

(f)      No consent, order, authorization, waiver, approval or any other action, or registration, declaration or filing with, any Person, board or body, public or private, is required to be obtained by Shell in connection with the execution, delivery or performance of this Agreement or the consummation of the transactions contemplated thereunder, other than the approval referred to in Section 2.1 and other governmental approvals with respect to the operation of the Plant that are not required to be obtained at this time.

18.3     Covenants of Shell. As a material inducement to Gulf Power to enter into this Agreement, Shell covenants that it will cause Owner to (a) give all required notices and procure and maintain at Owner’s expense all Permits necessary for it to perform this Agreement, (b) not amend, modify, terminate or waive any of Owner’s rights under Energy Interconnection Agreement without the prior written consent of Gulf Power, which consent shall not be unreasonably withheld, (c) procure and maintain in effect at least such insurance coverages as may be required by Applicable Laws, (d) operate the Plant according to Prudent Generator Practices and this Agreement in order to maximize availability of the Plant, provided that a specific failure to comply with this Section 18.3(d) will not constitute a default unless it is determined by an arbitrator under Article 16 to constitute a default of a material obligation and the failure continues after the arbitration award is issued, and (e) perform on-line and off-line water washes of the Generating Units as may be required by Prudent Generator Practices and as may be reasonably requested by Gulf Power from time to time, provided that if an off-line water wash requested by Gulf Power would prevent the Plant from satisfying a Request for Energy, Shell shall promptly notify Gulf Power thereof and shall, unless otherwise directed by Gulf Power, postpone the off-line water wash until the next time that it can be performed without preventing the Plant from satisfying any Request for Energy.

18.4     Covenant of Gulf Power. As a material inducement to Shell to enter into this Agreement, Gulf Power covenants that it will not itself consume any Energy generated by the Plant if doing so would cause Shell or Owner to lose their status as exempt wholesale generators under the Public Utility Holding Company Act of 1935, as amended.

18.5 [Intentionally Omitted]

18.6     Warranty Disclaimers. EACH PARTY ACKNOWLEDGES THAT IT HAS ENTERED INTO THIS AGREEMENT AND IS CONTRACTING FOR THE DELIVERY AND RECEIPT OF GAS AND FUEL OIL AND THE PRODUCTION AND DELIVERY OF ENERGY BASED SOLELY UPON THE EXPRESSED REPRESENTATIONS AND WARRANTIES IN THIS AGREEMENT AND, SUBJECT TO THE MATTERS EXPRESSLY WARRANTED IN THIS AGREEMENT, SHELL ACCEPTS ALL GAS AND FUEL OIL DELIVERED UNDER THIS AGREEMENT, AND GULF POWER ACCEPTS ALL ENERGY DELIVERED UNDER THIS AGREEMENT, “AS-IS” AND “WITH ALL

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FAULTS.” SHELL AND GULF POWER NEGATE ANY OTHER REPRESENTATION OR WARRANTY, WRITTEN OR ORAL, EXPRESSED OR IMPLIED, INCLUDING ANY REPRESENTATION OR WARRANTY WITH RESPECT TO MERCHANTABILITY OR FITNESS FOR ANY PARTICULAR PURPOSE.

ARTICLE 19

MISCELLANEOUS PROVISIONS

19.1     Entire Agreement. This Agreement is the Parties’ complete and final expression of agreement on the matters addressed in this Agreement and supersedes all prior agreements, representations, understandings, offers and communications, whether oral or written.

19.2     Amendment. This Agreement can be amended only by a written agreement executed by authorized representatives of the Parties.

19.3     Severability. If any provision of this Agreement is held invalid or unenforceable, all other provisions shall not be affected. With respect to the provision held invalid or unenforceable, the Parties shall amend this Agreement as necessary to effect the Parties’ original intent as closely as possible.

19.4     No Waiver. If on any occasion a Party does not insist upon the performance of any term, condition or provision of this Agreement, such forbearance shall not operate or be construed as an acceptance of any variation in any term, condition or provision of this Agreement or relinquishment of any right under this Agreement. No waiver by either Party of any right or of any default by the other Party under this Agreement shall operate or be construed as a waiver of any other or further right or as a waiver of any future default, whether of like or different character or nature.

19.5     GOVERNING LAW. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED ACCORDING TO THE LAWS OF THE STATE OF FLORIDA, EXCLUDING ANY CHOICE OF LAW RULES OR PRINCIPLES THAT WOULD REQUIRE THE APPLICATION OF LAWS OF A DIFFERENT JURISDICTION. THE PARTIES AGREE TO SUBMIT TO THE EXCLUSIVE JURISDICTION OF EITHER THE CIRCUIT COURT IN PENSACOLA, FLORIDA OR THE U.S. DISTRICT COURT FOR THE NORTHERN DISTRICT OF FLORIDA, AS APPROPRIATE.

19.6     Preparation of Agreement. This Agreement was prepared jointly by the Parties, each Party having had access to advice of its own counsel, and not by either Party to the exclusion of the other Party, and shall not be construed against one Party or the other as a result of the manner in which this Agreement was prepared, negotiated or executed.

19.7     Relationship of the Parties. This Agreement shall not be interpreted or construed to (a) create an association, joint venture or partnership between the Parties, (b) impose any partnership obligation or liability on either Party, or (c) be a lease of any property of any kind (provided that the rights and obligations of the Parties hereunder shall not be affected by any unanticipated or adverse tax or accounting characterization of this Agreement). Neither Party shall have any right, power or authority to enter into any agreement or undertaking for, or act on behalf of, or to act as or be an agent or representative of, or otherwise to bind, the other Party.

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19.8     No Third-Party Rights. This Agreement is intended solely for the benefit of the Parties and nothing in this Agreement shall be construed to create any duty to, standard of care with reference to, or any liability to, any Person not a party to this Agreement. Gulf Power further understands and agrees that Owner is an independent party, and Shell has no operational control over Owner and does not act for or on behalf of Owner in any way. Shell has no authority to bind Owner or commit Owner to any course of action. Gulf Power is not a third party beneficiary of any agreement between Shell and Owner, and neither Shell nor Gulf Power are third party beneficiaries of any agreement between Owner and any other party.

19.9     Notices. Except as otherwise expressly provided in this Agreement, all notices and other communications to be given or made under this Agreement shall be in writing, shall be addressed as specified below, and shall either be personally delivered or sent by courier, by registered or certified mail, or by facsimile. Initially, the respective addresses and facsimile numbers of the Parties and Owner are:

If to Shell:

Shell Energy North America (US), L.P.

909 Fannin, Plaza Level 1

Houston, Texas 77010

Attention: Power Contracts Manager

Facsimile: (713) 767-5414

With a copy to:

Shell Energy North America (US), L.P.

909 Fannin, Plaza Level 1

Houston, Texas 77010

Attention: General Counsel

Facsimile: (713) 230-2900

Wire Transfer Information:

Shell Energy North America (US), L.P.

Citibank

Account Number: 30603873

ABA#: 021000089

Any questions regarding wire transfer to Shell should be directed to:

Shell Energy North America (US), L.P.

Manager of Financial Accounting & Treasury Services

Phone: (713) 767-5425

Facsimile: (713) 767-5445

If to Gulf Power:

Gulf Power Company

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One Energy Place

BIN 0335

Pensacola, FL 32520

Attn: Raymond W. Grove

Telephone: 850-444-6695

Facsimile: 850-444-6705

With a copy to:

Gulf Power Company, Corporate Counsel

One Energy Place

BIN 0335

Pensacola, FL 32520

Attn: Jeff A. Stone

Telephone: 850-444-6550

Facsimile: 850-4669-3330

Wire Transfer Information:

Gulf Power Company

Bank of America

Account Number: 3751527855

ABA Number: 026009593

Any questions regarding wire transfer to Gulf should be directed to:

Gulf Power Company

Cash Operations Principal

Telephone: 404-506-0709

Facsimile: 404-506-0735

If to Owner:

Tenaska Alabama II Partners, L.P.

1044 North 115th Street, Suite 400

Omaha, Nebraska 68154

Attention: Managing General Partner

Facsimile: (402) 691-9575

All notices shall be deemed delivered (a) when presented personally, (b) if received at or before 5:00 p.m. Central Prevailing Time on a Business Day for the receiving Party, when transmitted by facsimile to the receiving Party’s facsimile number specified above and, if received on a Day that is not a Business Day for the receiving Party or after 5:00 p.m. Central Prevailing Time on a Business Day for the receiving Party, on the first Business Day following the date transmitted by facsimile to the receiving Party’s facsimile number specified above, (c) one Day after being delivered to a courier

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for overnight delivery, addressed to the receiving Party at the address specified above (or such other address as the receiving Party may have specified by written notice delivered to the delivering Party at its address or facsimile number specified above) or (d) five Days after being deposited in a United States Postal Service receptacle, postage prepaid, registered or certified, return receipt requested, addressed to the receiving Party at the address specified above (or such other address as such the receiving Party may have specified by written notice delivered to the delivering Party at its address or facsimile number specified above). Any Party may by written notice change the address or facsimile number, or both, to which notices and communications are to be sent.

19.10   Alternate Index. For any period for which an index referred to in this Agreement is not available, the index applicable to such period shall be the index for the next subsequent period for which the index is available. If either any index referred to in this Agreement or the publication used to ascertain the index ceases to exist or be published, and if the Parties do not agree on an alternate index or price source within one Month of the date on which such index or trade publication ceases to exist or be published, then either Party may refer the selection of an alternate index or price source to arbitration in accordance with Article 16. From the Day that such index or trade publication ceases to exist or be published, until the Day that an alternative index or price source is selected by agreement or determined by arbitration in accordance with Article 16, payments shall be made in the interim on the basis of the prices quoted in the relevant index or price source for the Day prior to the Day on which such index or price source ceased to exist or be published, as the case may be. When an alternative index or price source is determined by agreement or arbitration, the amounts paid by either Party to the other Party under this Agreement during the period of time described in the preceding sentence of this Section 19.10 shall be adjusted to reflect the alternative index or price source selected as provided herein. If either Party is found to owe payment to the other pursuant to this adjustment, payment shall be made by the owing Party with interest accruing at the Prime Rate as reported in the Money Rates column of The Wall Street Journal on the last Business Day of the preceding Month, compounded and calculated monthly from the date the adjusted amounts would have been due until the dates such adjustments are paid.

19.11   FERC Standard of Review. (a)Absent the express written agreement of both Parties to the proposed change, the standard of review for changes to any rate, charge, classification, term or condition of this Agreement, whether proposed by a Party (to the extent that any waiver in subsection (b) below is unenforceable or ineffective as to such Party), a non-party or FERC acting sua sponte, shall solely be the “public interest” application of the “just and reasonable” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956) and clarified by Morgan Stanley Capital Group, Inc. v. Public Util. Dist. No. 1 of Snohomish, 554 U.S. __ (2008).

(b)      In addition, and notwithstanding the foregoing subsection (a), to the fullest extent permitted by Applicable Law, each Party, for itself and its successors and assigns, hereby expressly and irrevocably waives any rights it can or may have, now or in the future, whether under §§ 205 and/or 206 of the Federal Power Act or otherwise, to seek to obtain from FERC by any means, directly or indirectly (through complaint, investigation or otherwise), and each hereby covenants and agrees not at any time to seek to so obtain, an order from FERC changing any section of this Agreement specifying the rate, charge, classification, or other term or condition agreed to by the Parties, it being the express intent of the Parties that, to the fullest extent permitted by Applicable

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Law, neither Party shall unilaterally seek to obtain from FERC any relief changing the rate, charge, classification, or other term or condition of this Agreement, notwithstanding any subsequent changes in Applicable Law or market conditions that may occur. In the event it were to be determined that Applicable Law precludes the Parties from waiving their rights to seek changes from FERC to their market-based power sales contracts (including entering into covenants not to do so) then this subsection (b) shall not apply, provided that, consistent with the foregoing subsection (a), neither Party shall seek any such changes except solely under the “public interest” application of the “just and reasonable” standard of review and otherwise as set forth in the foregoing section (a).

ARTICLE 20

REQUIRED REGULATORY APPROVALS

20.1     This Agreement shall be effective when executed by both parties, subject to termination as provided in this Article 20 and in other sections of this Agreement. Gulf Power shall use its reasonable efforts to obtain FPSC approval of this Agreement and in furtherance thereof, shall file a petition for approval as soon as reasonably practicable after execution of this Agreement, and diligently pursue such FPSC approval. Shell agrees to assist and support Gulf Power, in a timely manner and to the extent reasonably requested by Gulf Power, in obtaining FPSC approval.

20.2     If, after two hundred forty (240) Days from the filing date by Gulf Power of a petition with the FPSC for approval of this Agreement, the FPSC has not approved this Agreement through the issuance of a final, non-appealable order, with or without qualifications or conditions, then Gulf Power or Shell may terminate this Agreement upon written notice to the other Party, provided that such notice is delivered to such other Party no later than thirty (30) Days after the 240 Days from the FPSC filing date. If such Party fails to exercise the aforementioned termination right within such thirty (30) Day period, then such Party shall be deemed to have waived such termination right. Each Party agrees that it will not oppose, protest or contest the petition with the FPSC for approval of this Agreement. Notwithstanding the foregoing, if at any time the FPSC issues a final, non-appealable order that is subject to material qualifications or conditions that adversely affect Gulf Power, Gulf Power shall have a unilateral right to terminate this Agreement if such material qualifications or conditions are not acceptable to Gulf Power. Within fifteen (15) Days of the issuance of the FPSC order, Gulf Power shall provide Shell with a written notice of whether the FPSC order is subject to material qualifications or conditions and, if so, whether the material qualifications or conditions are acceptable to Gulf Power. If Gulf Power fails to provide such notice within such fifteen (15) Day period, the form of the FPSC order will be deemed to be acceptable to Gulf Power. Once the final, non-appealable order approving this Agreement has been issued and is deemed accepted by Gulf Power, the Parties agree they will not seek to amend, oppose, protest or contest such FPSC order and will undertake reasonable efforts to support the order if any entity seeks to amend, oppose, protest or contest such FPSC order. Upon a termination pursuant to this section, neither Party shall have any liability to the other Party hereunder.

ARTICLE 21

CHANGE OF LAW

A “Change of Law” means a change in an Applicable Law including a new environmental or tax law or regulation or a new interpretation of an existing environmental or tax

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law or regulation, which change is enacted after the execution date of this Agreement, and which generally affects the cost of electric generation. The Parties acknowledge that any payments, including the Capacity and Energy Payments, made by Gulf Power shall not be altered as a result of a Change of Law that causes either Party to incur additional costs or realize savings in carrying out its obligations under this Agreement.

ARTICLE 22

ACCOUNTING DETERMINATIONS

At the request of Gulf Power, throughout the term of the Agreement, Shell shall provide to Gulf Power public and non-public financial and business information reasonably necessary and required pursuant to applicable accounting publications for Gulf Power to make on-going accounting determinations with respect to the Agreement. To the extent Gulf Power is required to consolidate Shell as described in Article 22, Shell shall provide Gulf Power public and non-public financial and business information reasonably necessary for Gulf Power to prepare consolidated financial statements.

Gulf Power may terminate this Agreement upon 60 days prior written notice and without any liability imposed upon either Shell or Gulf Power if Gulf Power is required by any Applicable Law or any accounting standard, including but not limited to those implemented or administered by FASB or International Accounting Standards Board (IASB), to consolidate Shell or any of its Affiliates or permitted assigns as a VIE in Gulf Power’s or any of its Affiliates’ financial statements; provided however, such consolidation shall not constitute basis for a termination of this Agreement if at the end of such 60 day notice period, (1) the contractual rights of Shell to the power output of the Plant represents forty percent (40%) or less of the controlled generating capacity of Shell or (2) the contractual rights of Shell to the power output of the Plant represents forty percent (40%) or less of the controlled generating capacity plus other Variable Interests of Shell or (3) Shell’s equity is at least 10% of its total capitalization (net equity plus long term debt) or greater as the case may be to ensure the equity is sufficient to permit Shell to finance its activities.

******

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To evidence their acceptance of this Agreement, the Parties have caused their authorized representatives to sign below as of the Effective Date.

SHELL ENERGY NORTH AMERICA (U.S.), L.P.

By:/s/ Mark Quartermain

Name: Mark Quarterman

Title:   President

GULF POWER COMPANY

By:/s/ Theodore J. McCullough

Name: Theodore J. McCullough

Title:   Vice President

Attest:Susan D. Ritenour

Susan D. Ritenour

Secretary and Treasurer

To

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EXECUTION COPY CONFIDENTIAL

EXHIBIT 4.1

CAPACITY RESERVATION RATE AND

VARIABLE ENERGY RATE

Beginning at the inception of the Operating Term, the Capacity Reservation Rate per Month per MW of Contract Capacity shall be:

	Capacity Reservation Rate per Month ($/MW)
June 2009	[**]
July 2009	[**]
August 2009	[**]
September 2009	[**]
October 2009	[**]
November 2009	[**]
December 2009	[**]
January 2010	[**]
February 2010	[**]
March 2010	[**]
April 2010	[**]
May 2010	[**]
June 2010 – May 2014	[**]
June 2014 and each Month thereafter	[**]

Beginning at the inception of the Operating Term, the Variable Energy Rate per MWh shall be:

Month of the Operating Term		Variable Energy Rate ($/MWh)
January-December	2009	[**]
January-December	2010	[**]
January-December	2011	[**]
January-December	2012	[**]
January-December	2013	[**]
January-December	2014	[**]
January-December	2015	[**]
January-December	2016	[**]
January-December	2017	[**]
January-December	2018	[**]
January-December	2019	[**]
January-December	2020	[**]
January-December	2021	[**]
January-December	2022	[**]
January-May	2023	[**]

Exhibit 4.1-1

EXECUTION COPY CONFIDENTIAL

EXHIBIT 4.2

TEST PROCEDURES

PART A. GENERAL

The Capacity Test will determine the Contract Capacity of the Plant. Except for the Capacity Test under Section 4.2, each Capacity Test shall be scheduled to take place when the ambient temperature is forecasted to be higher than 85°F and shall be performed when the ambient temperature is actually higher than 85°F (unless Gulf Power waives this requirement and the evaporative coolers are in service, provided that these requirements shall not apply to Capacity Tests under Section 4.3(b) if complying with such requirements would cause a delay of more than ten Days in conducting a Capacity Test. If in any Contract Year the ambient temperature is not higher than 85°F for a continuous four-hour period between May 1 and May 15 when the Plant is available for a Capacity Test, the requirement of the preceding sentence regarding an ambient temperature of higher than 85°F shall not apply for such Contract Year. In establishing the Contract Capacity Shell will take into consideration the results of the Capacity Test as provided in Sections 4.2 and 4.3. The Capacity Test will be in accordance with the following section B of this Exhibit 4.2.

Exhibit 4.1-2

EXECUTION COPY CONFIDENTIAL

PART B.

Contents

1.0 INTRODUCTION 4

1.1 OBJECTIVE 4

1.2 OVERVIEW 4

1.3 UNIT DESCRIPTION 5

1.4 REFERENCES AND STANDARDS 5

2.0 TEST BASIS 7

2.1 Base Reference Conditions 7

3.0 THERMAL PERFORMANCE TEST 9

3.1 Division of Responsibilities 9

3.1.1 Shell Responsibilities 9

3.1.2 Gulf Power Responsibilities 10

3.2 Test Conditions 10

3.2.1 General Test Conditions 10

3.2.2 Test Timing 10

3.2.3 Test Prerequisites 11

3.2.4 Valve Position Lineups 12

3.2.5 Auxiliary Load Status 12

3.2.6 Pre-Test Activities 12

3.2.7 Post-Test Activities 13

3.3 Test Data Requirements 13

3.3.1 Data Collection 13

3.3.2 Data Elimination 14

3.3.3 Data Reduction 14

3.3.4 Quality Assurance 14

3.4 Measurements and Instrumentation 14

3.4.1 Instrument Selection 14

3.4.2 Calibration Requirements 14

3.4.3 Redundancy 15

3.4.4 Primary Variables 15

3.4.5 Secondary Variables 17

3.5 Test Calculations 17

3.5.1 Fundamental Equations – Measurements 17

3.5.2 Fundamental Equations – Corrections 18

3.5.3 Correction Factor Equations 19

3.6 Test Results 20

3.7 Test Measurement Uncertainty 20

3.8 Test Report 20

Exhibit 4.2-1

4.0 CAPACITY TESTS 20

4.1 Division of Responsibilities 20

4.1.1 Shell Responsibilities 21

4.1.2 Gulf Power Responsibilities 21

4.2 Test Conditions 21

4.2.1 General Test Conditions 21

4.2.2 Test Timing 22

4.2.3 Test Prerequisites 22

4.2.4 Valve Position Lineups 23

4.2.5 Auxiliary Load Status 24

4.2.6 Pre-Test Activities 24

4.2.7 Post-Test Activities 25

4.3 Test Data Requirements 25

4.3.1 Data Collection 25

4.3.2 Data Elimination 25

4.3.3 Data Reduction 25

4.3.4 Quality Assurance 26

4.4 Measurements and Instrumentation 26

4.4.1 Instrument Selection 26

4.4.2 Calibration Requirements 26

4.4.3 Redundancy 26

4.4.4 Primary Variables 27

4.4.5 Secondary Variables 28

4.5 Test Calculations 28

4.5.1 Fundamental Equations – Measurements 28

4.5.2 Fundamental Equations – Corrections 29

4.5.3 Correction Factor Equations 30

4.6 Test Results 31

4.7 Test Measurement Uncertainty 31

4.8 Test Report 31

APPENDICES

APPENDIX A PROJECT HEAT BALANCES

APPENDIX B VALVE POSITION LINEUPS

APPENDIX C TEST MEASUREMENT POINTS

APPENDIX D CORRECTION CURVES

APPENDIX E SAMPLE CALCULATION

Exhibit 4.2-2

1.0 Introduction

1.1 Objective

This Exhibit 4.2 serves as the test procedure for implementing the annual Tests referred to in the Agreement for the Plant. The objective of the tests is to determine the corrected Tested Heat Rate (THR) referred to in Section 8.3 of the Agreement and measure Plant capability used in establishing Contract Capacity and Power Augmentation Capacity referred to in Sections 4.2 and 4.3 of the Agreement. This procedure is intended to provide guidelines for the preparation and execution of the tests. The procedure set forth in this Exhibit 4.2 is intended as a guide, and an immaterial failure to follow the procedure in exact detail will not invalidate test results unless there is a reasonable basis to believe that such failure may have altered the results or the reliability of the results.

1.2 Overview

The following tests will be conducted annually in compliance with the Agreement.

• Heat Rate Test

• Capacity Tests

• Capacity Test 1 – Without Power Augmentation

• Capacity Test 2 – With Power Augmentation

• Combustion Turbine Evaporative Cooler Tests (included in above if possible)

The tests are described in detail in subsequent sections. Section 2.0 summarizes the basis for each test including Base Reference Conditions, design fuel analysis, and equipment in service. Section 3.0 covers the Heat Rate Test. ASME PTC 46, Performance Test Code on Overall Plant Performance will be used as a guideline to conduct this test. Section 4.0 covers the Capacity Tests and associated Evaporative Cooler Testing.

A preliminary schedule and overview of testing is described below. This schedule will be adjusted by Shell as necessary. All testing under this Exhibit 4.2 will be performed using natural gas only. A one-hour stabilization period is recommended prior to each test.

One two-hour Heat Rate Test and two two-hour Capacity Tests will be performed sequentially over an estimated eight-hour test period once per year. The Heat Rate Test will be conducted at baseload with no duct firing or Power Augmentation in accordance with the Heat Rate Test procedure presented in Section 3.0 of this Exhibit 4.2. As indicated in the procedure and Table 2.1, test results will be corrected to 68°F compressor inlet temperature. The corrected Tested Heat Rate (THR) will be used as outlined in Section 8.3 of the Agreement to determine what Heat Rate Payments, if any, shall be made by either Party.

Upon completion of the Heat Rate Test the Plant will be reconfigured with maximum duct firing to fully load the Steam Turbine with no Power Augmentation to the Combustion Turbines in preparation for Capacity Test 1. The test will begin once the Plant has reached steady state. Upon completion of Capacity Test 1 the Plant will be reconfigured with maximum duct firing to fully load the Steam Turbine with Power Augmentation to the Combustion Turbines in preparation for Capacity Test 2. The test will begin once the Plant has reached steady state. The Capacity Tests will be conducted in accordance with the Capacity Test Procedure presented in Section 4.0 of this Exhibit. As indicated in the procedure and Table 2.1, Capacity Test results will be corrected to summer design ambient temperature conditions of 99°F dry bulb and 76°F wet bulb. The corrected results of Capacity Test 2 will be used to establish Contract Capacity as outlined in Sections 4.2 and 4.3 of the Agreement. The corrected results of Capacity Test 1 will be subtracted from the corrected results of Capacity Test 2 to determine the amount of Tested Plant Power Augmentation Capability. This in turn will be used to determine the Power Augmentation Capacity (PAC) of each Combustion Turbine as outlined in

Exhibit 4.2-3

Section 1 and Sections 4.2 and 4.3 of the Agreement.

1.3 Unit Description

The Plant consists of a 3x1 combined cycle block including the following major equipment.

• Three General Electric (GE) PG7241(FA) combustion turbine generators (CTGs) firing natural gas and fuel oil (for backup only).

• One GE reheat, single LP admission, dual-flow LP, condensing, down exhaust, steam turbine generator (STG).

• Three three-pressure, reheat, supplemental fired heat recovery steam generators (HRSGs).

• One dual-pass steam surface condenser.

• One counterflow cooling tower.

1.4 References and Standards

Principles, formulas, and data from the following references and standards will be used wherever applicable to the methods and calculations included in this test procedure.

[1] ASME PTC 46-1996, Performance Test Code on Overall Plant Performance

[2] ASME PTC 1-1991, General Instructions

[3] ASME PTC 22-1997, Performance Test Code on Gas Turbines

[4] ASME PTC 4.4-1981, Gas Turbine Heat Recovery Steam Generators

[5] ASME PTC 6-1996, Steam Turbines

[6] ASME PTC6R-1985, Guidance for Evaluation of Measurement Uncertainty

[7] ASME PTC 3.3-1969, Gaseous Fuels

[8] ASME PTC 19 Series, Instruments and Apparatus

[9] ASTM D1945-1996, Standard Test Method for Analysis of Natural Gas by Gas Chromatography

[10] ASTM D3588-1988, Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels

[11] AGA Report No. 7 - 1996, Measurement of Gas by Turbine Meters

[12] AGA Report No. 8 - 1994, Compressibility and Supercompressibility for Natural Gas and Other Hydrocarbon Gases

[13] ASME MFC 3M-1989 (ISO 5167), Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi

[14] API 14.3 (AGA 3)-1990, Manual of Petroleum Standards, Natural Gas Fluids Measurement, Orifice Meters

[15] ASME Steam Tables, 1967

Exhibit 4.2-4

[16] ASHRAE Pyschrometric Charts

[17] SUPERTRAPP 1.07-1990, “NIST Thermophysical Properties of Hydrocarbon Mixtures”

[18] NASA Reference Publication 1311, Computer Program for Calculation of Chemical Equilibrium Compositions and Applications, Part 1 - Oct. 1994, Part II - June 1996, Data Download - Aug 1999

Exhibit 4.2-5

2.0 Test Basis

2.1 Base Reference Conditions

The Base Reference Conditions for the Tests are presented in the following tables.

Table 2-1 Base Reference Conditions
Parameter	Heat Rate Test	Capacity Test1	Capacity Test2
Fuel	Natural Gas	Natural Gas	Natural Gas
Barometric Pressure, psia1	14.5	14.5	14.5
Ambient Dry Bulb Temperature, °F2	[**]	[**]	[**]
Ambient Relative Humidity, %	[**]	[**]	[**]
Ambient Wet Bulb Temperature, °F2	[**]	[**]	[**]
Evaporative Coolers2	[**]	[**]	[**]
CTG Compressor Inlet Temperature, °F2	[**]	[**]	[**]
CTG Compressor Inlet Relative Humidity, %	[**]	[**]	[**]
Duct Burners	Off	On3	On3
Power Augmentation	Off	Off	On
HRSG Drum Blowdown, % of Feedwater4	0.0	As Required	As Required
Equipment in Service	Table 2-2
Notes: 1.             Based on an assumed site elevation of [**] feet above seal level. Slight adjustment to the number may be required once the final elevation is determined. 2.             For the Heat Rate Test corrections for Combustion Turbine impacts on Plant performance will be based on compressor inlet temperature, not ambient temperature. For the Capacity Tests the compressor inlet temperature will be determined (TBD) based on the results of the evaporative cooler test. The evaporative coolers will not be in service for dry bulb temperatures less than 60 °F and wet bulb depressions less than 10°F. If the evaporative cooler test cannot be conducted concurrently with the performance test, it will be conducted at a time mutually agreeable to Shell and Gulf Power and the performance test results will be subsequently adjusted. The evaporative cooler effectiveness from the previous test (or the design effectiveness of 85% if no other test had been performed previously) will be used in the interim. 3.             Duct burners will be fired as required to achieve the maximum allowable throttle pressure of approximately 1,871 psia for the Capacity Tests. 4.             Blowdown should be isolated for Heat Rate Test to allow for proper steam flow calculators.

Exhibit 4.2-6

Table 2-2 Expected Equipment in Service
The following list is the expected equipment in service during the tests. Deviators are sometimes necessary or beneficial to overall Plant efficiency and should be noted prior to test commencement. No corrections for auxiliary loads will be made unless deemed appropriate and agreed upon by the Parties.
Equipment Description	Number Installed	Number in Service
		Heat Rate Test	Capacity Tests
Combustion Turbines	3	3		3
Evaporative Coolers	3	31		31
Power Augmentation	3	0		3
HRSGs	3	3		3
Duct Burners	3	0		3
Steam Turbines	1	1		1
Fuel Gas Heaters	3	3		3
Boiler Feed Pumps	6	3		3
Condensate Pumps	3	2		2
Circulating Water Pumps	3	2		2
Cooling Tower Fans	14	As Required		As Required
Cooling Tower Makeup Pumps	2	As Required		As Required
Aux Cooling Water Pumps	2	1		1
Closed Cycle Cooling Water Pumps	2	1		1
Fresh Water Pumps	2	1		1
Demineralized Water System	1	02		1
Demineralized Water Pumps	2	As Required		As Required
Cycle Chemical Feed System	1	As Required		As Required
Circulating Water Chemical Feed System	1	As Required		As Required
HRSG Sump Pumps	2	0		As Required
Fire Water Pumps	2	0		0
Fire Water Pressure Maintenance Pump	1	1		1
Air Compressors	2	As Required		As Required
Condensor Air Extraction Skids	2	As Required		As Required
Fuel Oil Unloading Pumps	3	0		0
Fuel Oil Supply Pumps	4	0		0
CTG Water Injection Pumps	3	0		0
Chemical Waste Treatment System	1	1		1
Generator Stepup Transformers	4	4		4
Auxiliary Transformers	2	2		2
Combustion Turbine Auxiliaries3		As Required		As Required
Steam Turbine Auxiliaries3		As Required		As Required
Misc. Plant Loads		As Required		As Required

Exhibit 4.2-7

Notes:

1.             See Note 2 on Table 2-1.

2.             The cycle demin and makeup system should be shut down during the Heat Rate Test. However, if it becomes necessary to maintain evaporative cooler makeup, the system may be put into service.

3.             Ensure redundant HVAC, pumps, vapor extractors, etc. are not in service.

Exhibit 4.2-8

3.0 Thermal Performance Test

The Heat Rate Test will be conducted annually according to Section 8.3 of the Agreement to determine the corrected Tested Heat Rate (THR). The corrected Tested Heat Rate will be used as outlined in Section 8 of the Agreement to determine what Heat Rate Payments, if any, shall be made by either Party. The test will consist of two (2) one-hour test periods.

The Heat Rate Test will be conducted in general accordance with PTC 46 using an overall plant test concept. Corrections will be applied to measured test results to account for variations in the Base Reference Conditions (Table 2-1) such as ambient temperature and barometric pressure. No test measurement uncertainties will be applied to the corrected test parameters in the determination of test results. The following sections provide the general procedures for set-up and execution of the test and for determining test results.

3.1 Division of Responsibilities

This section describes the division of responsibilities in the preparation and conduct of the Heat Rate Test.

3.1.1 Shell Responsibilities

The responsibilities of Shell prior to, during, and after the tests include the following.

• Provide detailed test procedures to govern the conduct of the performance test as prepared by Owner.

• Provide procedures for data acquisition, data backup, and methods of data analysis as prepared by Owner.

• Provide parameters to be manually collected and recorded as determined by Owner.

• Cause Owner to ensure that the distributed control system (DCS) data collection is operational and the archival deadbands have been properly established prior to commencement of testing.

• Cause Owner to coordinate test setup and calibration activities.

• Cause Owner to conduct any necessary pre-tests.

• Cause Owner to verify that major equipment operates at or near design conditions at steady state.

• Cause Owner to ensure that permanent and temporary instrumentation required for the tests and for proper operation/control of the Unit is properly installed, calibrated, and operating.

• Provide instrument calibration records as prepared by Owner to Gulf Power.

• Provide proper notice to Gulf Power of the intended test schedule.

• Cause Owner to provide personnel to collect test data as necessary.

• Cause Owner to designate a Performance Test Director (PTD) with the overall responsibility for the direction and conduct of the tests.

• Cause Owner to provide technical direction to the operators throughout the test.

• Cause Owner to establish and report auxiliary loads in service and valve position lineups during the test.

• Cause Owner to manage the collection of test data and fuel samples.

• Cause Owner to calculate specified performance parameters from measured test data.

• Cause Owner to Perform calculations to adjust test results to the Base Reference Conditions.

• Cause Owner to provide fuel sampling containers and obtain laboratory analysis of fuel

Exhibit 4.2-9

samples.

• Submit a complete test report as prepared by Owner.

3.1.2 Gulf Power Responsibilities

The responsibilities of Gulf Power prior to, during, and after the tests include the following.

• Arrange for the transmission of power downstream of the Energy Point of Delivery.

• Arrange for adequate supply of Gas according to the Agreement.

• Designate representatives to witness tests.

• Provide approval of test results within a reasonable time.

3.2 Test Conditions

The following sections describe the test conditions including the general operating conditions, the test boundary, test prerequisites, and the cycle valve lineup for the test.

3.2.1 General Test Conditions

• Base Reference Conditions are listed in Tables 2-1 through 2-3.

• The project design heat balances are provided in APPENDIX A.

• The tests will be conducted in accordance with this document which is agreed upon by Gulf Power, Shell and Owner. Conflicts in test methods will be resolved using the following order of precedence.

1. Sections 1, 2, and 3 of this Exhibit 4.2

2. ASME PTC 46

• If test conditions differ from those indicated in Table 2-1, corrections will be calculated and applied to data in accordance with the methods outlined in Section 3.5.

• All air, steam, water, and generator conditions which have an effect on the data collected for the determination of the corrected test results will be regulated as near as possible to the conditions indicated in the Project Heat Balances corresponding with the expected performance levels. OEM requirements for continuous and long-term operation, such as Steam Turbine inlet temperature and Combustion Turbine base load control curve, will not be exceeded.

• The Plant will be operated from the control room with systems operating in automatic mode which are normally operated in automatic mode, and in a manner consistent with Prudent Generator Practices for continuous and long-term operation.

• For conditions beyond the control of Owner, Shell or Gulf Power, reasonable efforts will be made to conduct the tests as close as possible to the Base Reference Conditions to minimize the magnitude of the applied correction factors, subject to the requirements of Part A of this Exhibit 4.2.

• The HRSGs will be operated with zero HRSG blowdown. No corrections for blowdown will be applied.

• Reasonable efforts will be made to conduct the tests with all Plant components in a clean and undamaged condition.

• Evaporative coolers will be in service if ambient dry bulb temperature is 60° F or greater, and if the wet bulb depression is at least 10° F.

3.2.2 Test Timing

The Heat Rate Test will consist of two (2) one-hour test periods following a minimum one-hour stabilization period. The test will be scheduled according to the requirements of Section 8.3 of the Agreement. The test will be conducted after any pretests required by the Owner.

The two (2) one-hour test runs will be continuous, provided steady state conditions are maintained.

Exhibit 4.2-10

If steady state conditions cannot be maintained, the test will be suspended until steady conditions return. When steady state conditions return the test may be resumed.

Preliminary thermal performance testing may be conducted and the resulting data analyzed prior to the actual test at the discretion of Gulf Power. Preliminary testing may be used for checking the operation and readings of all instruments directly related to the test and for the training of observers and other test personnel. Data will be collected and evaluated during preliminary testing to determine if abnormalities exist with the data.

3.2.3 Test Prerequisites

Prior to conducting a test, a number of prerequisites must be fulfilled to ensure the Plant is in test-ready condition. Some of these activities are optional based on the number of operating hours on the equipment and based on the history of operation during the commissioning process. Shell may add to or delete from this list as appropriate.

• Pre-operational testing and normal startup procedures will be completed.

• All permanent and temporary instrumentation required for the test will be calibrated, installed, and loop checked. DCS and test data acquisition system (DAS) configurations and ranges will be verified.

• Calibrations for temporary test instrumentation will be current. Plant instruments for primary measurements will be zero and span checked as appropriate.

• DCS data logs will be set up and verified to collect primary and secondary data.

• The local inlet guide vanes (IGVs), position indicators, and control system IGV indications will be checked for correspondence and that they correctly indicate full open position.

• The accuracy and calibration of the compressor discharge pressure measurements which are used to control the Combustion Turbines at base load will be confirmed.

• It will be verified that the proper Combustion Turbine base load exhaust temperature control algorithm is input into the control system and is operating properly (confirm that a commissioning curve which results in lower than base load turbine inlet temperatures is not being used).

• The Combustion Turbine compressor, inlet scroll, and IGVs will be cleaned and inspected. This will be done with an offline compressor water/detergent wash.

• The Combustion Turbine fuel nozzles may be removed and visually inspected if deemed necessary by Shell.

• Throttle valves may be inspected, cleaned, and/or adjusted to achieve design tolerances if deemed necessary by Shell.

• The Combustion Turbine inlet air filter system cleanliness will be verified by visual inspection and pressure drop measurement.

• Preliminary test data will be analyzed to identify incorrect readings or incorrect operating modes and to assess the actual performance characteristics of all major equipment throughout the cycle.

• Condenser pressure measurements will be compared for consistency and for reasonable correspondence with condensate temperatures. Vacuum pressure transmitter legs will be evacuated prior to testing to eliminate any possible water leg buildup.

• Control system tuning will be complete to provide reasonably dampened drum level and flow oscillations. Natural gas supply pressure to the Combustion Turbines will be reasonably stable.

• Water legs on pressure measurements and any vertical flow measurements will be documented.

• Primary flow elements may be inspected, where possible, and configuration of the flow metering systems documented.

• Preliminary tests may be run as necessary to confirm any of the above information.

• The startup and operations personnel will be familiar with the valve position lineups and auxiliary load lineups for the test, as described in the following sections. The time required to complete the isolations should be determined.

Exhibit 4.2-11

• Fuel sampling containers and sampling connections will be identified and acquired. A laboratory fuel analysis will be identified and a pre-test sample may be collected and analyzed.

• Personnel required to collect any manual test data and fuel samples will be identified by the Owner and trained by the PTD.

3.2.4 Valve Position Lineups

During a test, the valve position lineups will be in accordance with the valve lineup list provided in APPENDIX B. Main system valves will be in the normal operating position with the exception of those noted in the list. HRSG and Steam Turbine bypasses, drains, and vents should be isolated to the fullest extent possible. Cascading, continuous, and intermittent blowdown valves will be isolated. Automatic valves will remain in their normal mode of operation. Specific automatic valves noted in the list will be checked for leakage/seepage and may be manually isolated if required.

Leakages and seepages should be identified in all main system valves, and reasonable efforts will be made by the Owner’s to minimize these cycle losses. Any valve not positioned in accordance with APPENDIX B will be documented and reported to the PTD prior to testing. The safe and prudent operation of any Generating Unit will not be compromised to minimize cycle losses during a test.

3.2.5 Auxiliary Load Status

The auxiliary loads in service during a test will be established as the loads required to sustain continuous safe operation of the Generating Units. The expected operating status of major equipment is indicated in Table 2-3. Deviations from this list may be necessary or beneficial and will be documented prior to test commencement. Redundant loads, such as some HVAC, pumps, and vapor extractors, will not be in service. No corrections will be applied for auxiliary loads in service unless deemed appropriate.

3.2.6 Pre-Test Activities

Prior to initiating a test, the following activities must take place.

• Confirmation that the General Test Conditions and Test Prerequisites, as listed above, have been observed and will be obtained.

• A pre-test meeting will be held to assign test personnel and specific test responsibilities.

• A walkdown of the Plant will be conducted to familiarize test personnel with the location of equipment, instrumentation, etc. Watches will be synchronized with the indicated DCS time.

• The Combustion Turbines will be set to base load exhaust temperature control, and will be automatically controlled in a manner to simulate the heat balance corresponding to the expected performance levels and in accordance with Table 2-1. The Plant will be operated by the Owner’s operations staff under the direction of the PTD.

• Once base load is attained, the Plant will be allowed a minimum of one hour to reach steady state operation. Steady state is defined as follows.

1. The average Combustion Turbine exhaust temperature does not vary more than 5°F in fifteen minutes.

2. The Steam Turbine output does not vary more than 500 kW in fifteen minutes.

Outside influences such as ambient conditions will be monitored to ensure minimum variations in accordance with PTC 22, 6, and 4.4. However, exceedances of these specified variations will not invalidate a test.

• Instrumentation status will be checked including operation of the test data acquisition system (DAS).

• Valve position lineups will be verified.

Exhibit 4.2-12

• Auxiliary loads in service will be documented.

• Agreed deviations from the established procedures will be documented.

• Communications will be verified as necessary between the control room and the test personnel in the field. The PTD will ensure that all test personnel have been briefed and are on station with appropriate data forms and equipment.

• The PTD will announce the test start to all personnel.

3.2.7 Post-Test Activities

The following activities will take place at the conclusion of the test period.

• The PTD will announce the test end to all personnel.

• The test data will be collected and compiled.

• A copy of the compiled test data will be provided to Gulf Power.

• Copies of operator logs, chemistry logs, alarms, and equipment status changes during the test period will be provided to the PTD.

• Fuel samples will be sent to the laboratory for analysis.

• Final test results will be provided in the Test Report.

3.3 Test Data Requirements

The following test data requirements will be observed for the tests.

3.3.1 Data Collection

Data collected during a test may include any of the following.

• Data from Plant DCS.

• Data from test data acquisition system (DAS).

• Manually collected data.

• Fuel samples collected for laboratory analysis.

The test DAS will be used to collect data from any temporary test instruments. The Plant DCS will collect the remainder of the data including fuel gas parameters and net electrical output as well as all secondary measurements collected for information only. Some manual data may be collected as deemed necessary by the PTD. Copies of all raw data will be made available at the conclusion of the test for review.

Any manual data will be collected on intervals no greater than ten minutes. All electronically collected parameters will be scanned and logged as snapshots or rolling averages on intervals no greater than one minute to minimize precision error.

3.3.2 Data Elimination

Certain test conditions may require elimination of specific sets of data during the evaluation of test results. Depending on the circumstances, the test may be suspended, restarted, or the total test duration reduced. The following periods may be eliminated from consideration in the determination of test results as mutually agreed upon by the Shell, the Owner and Gulf Power.

• Periods when fuel parameters are outside the range of the Combustion Turbine manufacturer’s specifications.

• Periods when parameters outside the control of Shell or the Owner exhibit fluctuations in excess of the recommended allowable fluctuations as determined by the PTD.

Exhibit 4.2-13

• Periods when a Plant component trips but does not cause a generator trip.

• Periods when steady state conditions are not maintained.

3.3.3 Data Reduction

Raw data will be collected for each one-hour test period and averaged. Data reduction periods will not exceed one hour to minimize the impact of varying ambient conditions. Test calculations will be performed on a one-hour basis. Some raw data may include corrections for instrument laboratory calibration data if the corrections can be performed automatically in the DCS or DAS.

3.3.4 Quality Assurance

All raw data and reduced data will be controlled and maintained by Owner. Copies of all raw data will be made available to the Parties at the conclusion of the tests. Shell shall ensure that that all recorded data is accurate and complete, and maintained for future analysis.

3.4 Measurements and Instrumentation

A list of test measurement points and a corresponding test point diagram will be provided in APPENDIX C. The list and diagram summarize all measurements that will be taken during the test including measurements for the calculation of test results, backup measurements, and measurements allowing for the evaluation of individual Plant component performance. The following sections describe the selection of these instruments.

3.4.1 Instrument Selection

Test measurements will be generally based on the use of Plant instrumentation. However, for certain parameters that have high sensitivity coefficients to the calculated test results, precision test instrumentation may be used in accordance with PTC 46. Shell reserves the right to substitute precision test instrumentation in place of any Plant instrumentation to minimize the test measurement uncertainty and improve the confidence in test results. The instrumentation will be selected and calibrated in order to ensure that the overall test uncertainties are less than or equal to the default values.

3.4.2 Calibration Requirements

Shell shall cause Owner to provide current calibration records and/or factory certifications, traceable to appropriate standards, for all instrumentation critical to the calculation of test results (Class 1 primary variables) in accordance with PTC 46. Calibrations may take place at the Plant Site or at an independent instrumentation laboratory. Permanent Plant thermocouples which are wired to cold junctions in the DCS cabinets will provide “type” measurements and generally will not be calibrated. Calibration laboratories will be certified, traceable to nationally respected standards, and will maintain proper quality assurance procedures. Recalibration of test instruments after the tests will not be required unless, by mutual agreement between Shell, the Owner and Gulf Power, there is cause for concern regarding instrumentation drift during the testing program.

3.4.3 Redundancy

Redundant measurements will be collected by the DCS where available to facilitate detection of instrument reading errors and to provide backup measurements in case of on-line device or signal malfunctions during one test. If during a test period, or during the evaluation of the data after the test, obvious errors are found in the recorded data, those readings will be disregarded. The test period would be

Exhibit 4.2-14

considered valid provided the available backup data is considered to be correct at the discretion of the Owner.

3.4.4 Primary Variables

Measurements that are used in the calculation of test results are considered primary variables. They are further classified as Class 1 or Class 2 primary variables. Class 1 variables are those which have relative sensitivity coefficients of 0.2 or greater. Instruments for the primary variables were selected in accordance with PTC 46 requirements as presented in the following sections.

3.4.4.1 Electrical Power Measurements

The Net Plant Output is equivalent to the power delivered to the high voltage side of the four generator stepup transformers (GSUs). The as-tested Net Plant Output will be determined as the measured power to Alabama Power Company.

Power to Alabama Power Company (APC) will be measured with an APC supplied revenue quality (0.1%) power meter located in the switchyard control building. The associated metering PTs and CTs are specified as ANSI accuracy class [0.3% and 0.15%], respectively. The meter includes real time analog output MWh and MVAR signals to the DCS. The DCS values will be used as the primary measurement for test calculations. Local manual readings may be recorded as primary or secondary measurements at the Owner’s discretion.

As secondary net power measurements, there are watt/VAR transducers on the high voltage side of each of the four GSUs which provide analog signals to the DCS. The sum of these readings should be equivalent to the sum of the utility meter.

Combustion Turbine and Steam Turbine generator power output will be measured by watt/VAR transducers (0.2%) located at the terminals of each generator. Data will be collected electronically by the DCS via datalink with the Mark V. As a check, net power can be calculated as the sum of the four generator meters, less the AUX transformer meters, less the AUX transformer losses, less generator excitation, less GSU transformer losses.

For the measurement of Plant auxiliary loads, a secondary measurement, kW and kVAR will be determined at the low voltage side of each of the auxiliary (AUX) transformers. I/O points for these readings may need to be configured in the field.

CTG auxiliary loads will be determined manually from generator panel meters. CTG excitation power will be calculated from DC field volts and amps recorded in the DCS.

Any manual readings of MWh will be recorded approximately every 10 minutes. The average MW delivered for an hour will be the difference in the readings at the end and beginning of the hour divided by the precision time duration between readings.

3.4.4.2 Fuel Gas Flow Measurements

The Plant fuel gas flow measurements will be based on the permanent Plant orifice flow meter. The meter is a Vickery-Simms junior flow metering tube (or equal) with straightening vanes manufactured and installed in accordance with [14]. Signals of static pressure, temperature, and square root of differential pressure are sent to the DCS. The determination of fuel gas flow for the performance test will be based on manual calculations using the raw pressure, temperature, and differential pressure measurements in accordance with [12], [13], [14], [17], and/or [18] as appropriate, and in conjunction with the actual fuel gas analysis.

In addition to the pressure, temperature, and differential pressure at the orifice plate, the DCS also receives inputs from the Transco and/or SONAT online gas chromatograph. Outputs from the chromatograph to the DCS include constituent analysis, heating value, and specific gravity. Volumetric flow at standard conditions is calculated directly in the DCS using orifice data and chromatograph data in

Exhibit 4.2-15

conjunction with Bailey algorithms. This calculated flow will serve as a secondary measurement for the performance test.

Also secondary data, fuel gas flow measurements for each Combustion Turbine will be collected via the GE supplied permanent orifice flow meters on the fuel gas supply line to each Combustion Turbine and each HRSG. Actual readings of differential pressure, static pressure, and temperature will be collected from the associated permanent Plant instruments. Fuel gas mass flow will be calculated in accordance with [12], [13], [14], [17], and/or [18] as appropriate, and in conjunction with the actual fuel gas analysis.

3.4.4.3 Fuel Gas Analysis

Six fuel gas samples will be collected during each one-hour test period. Shell shall ensure that three samples from each hour will be analyzed and the other three will be held by the Owner as backup samples. Fuel gas sampling will be performed at a convenient location such as the connection for pressure indicator upstream of the Plant orifice flow meter or other sample or vent connection in the upper hemisphere of the pipe. Shell shall ensure that stainless steel fuel sampling containers and appropriate connections will be provided by Owner. Sampling procedures will be in accordance with [7]. Each sample will be clearing labeled with an identification number, project name, date, time, name of the person acquiring the sample, and the words “Methane, Compressed.”

Shell shall cause Owner to identify an independent authority to analyze the fuel gas samples, subject to mutual approval. The analysis will be performed in accordance with [9], [10], and [12], and will result in a report of constituting analysis (including chromatography charts showing peaks), lower and higher heating values (on a mass and volumetric basis), specific gravity, compressibility, and viscosity for each sample. Standard conditions should be specified as 60°F and 14.696 psia. In addition, the associated measurement uncertainties and quality assurance procedures should be provided by the laboratory.

Fuel gas properties at flow meter process conditions for the flow equations will be determined from the laboratory analysis and hydrocarbon mixture calculations based on [11], [16], and [17].

A permanent Plant chromatograph will be in service at the on-site Transco and SONAT monitoring stations upstream of the Plant orifice meter as a source of secondary fuel constituent data. The chromatograph analysis of ten (10) constituents plus heating value and specific gravity will be available as a local output as well as in the DCS. Calibration cycles will be set as necessary to maximize the accuracy of the chromatograph. Sampling/analysis results will be updated approximately every five to ten minutes.

3.4.4.4 Ambient Conditions Measurements

Ambient conditions will be measured by precision test instrumentation with outputs collected by the test DAS. Laboratory calibrations will verify instruments are within the required accuracies.

Ambient dry bulb temperature at each Combustion Turbine inlet will be measured using an array of nine 100-ohm platinum RTDs mounted upstream of the evaporative cooler, but shielded from solar radiation.

Ambient wet bulb temperature at each Combustion Turbine inlet will be measured with a mechanically aspirated psychrometer located near each Combustion Turbine inlet. Relative humidity will be calculated in accordance with [16].

Compressor inlet temperature will be measured with a minimum of 4 calibrated 100-ohm platinum RTDs mounted inside the inlet duct upstream of the IGVs. Compressor inlet humidity will be calculated based on the measured ambient wet bulb temperature.

Barometric pressure will be measured with a calibrated digital barometer or absolute pressure transmitter mounted in the vicinity of the Combustion Turbine inlet with proximity to the Combustion Turbine centerline elevation.

Ambient wet bulb temperature at the cooling tower will be measured with a minimum of two mechanically aspirated psychrometers located in the vicinity of the cooling tower.

3.4.5 Secondary Variables

Exhibit 4.2-16

Secondary variables are those measurements not directly used in the calculation of test results. These variables will be measured to provide backup readings for the primary variables, to allow the Owner to establish complete heat balance calculations around the cycle and individual Plant components, and to provide assistance in pinpointing any improper test operating condition. Secondary variables will generally be permanent Plant instrumentation. However, the Owner may choose to install a number of temporary test instruments to achieve more accurate results in evaluating individual component performance.

3.5 Test Calculations

To compare the measured test data to the expected performance levels, a number of calculations must be performed. First, the collected data is averaged for each one-hour test period. Then, the as-tested Net Plant Output and Plant fuel consumption are determined. Next, the as-tested Net Plant Output and fuel consumption are corrected to Base Reference Conditions using the correction curves to be provided in APPENDIX D. The corrected heat rate is determined from the corrected Net Plant Output and fuel consumption. The results of the Heat Rate Test will be determined as the average of the two sets of corrected Net Plant Output and heat rate values.

The fundamental equations to perform the test calculations are laid out in the following sections. These equations, based on PTC 46, explain how to arrive at the corrected Plant performance using the correction curves from APPENDIX D. A sample calculation will be provided in APPENDIX E.

3.5.1 Fundamental Equations - Measurements

3.5.1.1 As-Tested Net Plant Output

The calculation of as-tested Net Plant Output is as follows:

P_meas = as-tested Net Plant Output, kW

3.5.1.2 As-Tested Plant Fuel Consumption

The calculation of as-tested Plant fuel consumption is as follows:

Qmeas	=	HHV x qtotal
where:
Qmeas	=	as-tested Plant fuel consumption, Btu/h (HHV)
HHV	=	fuel higher heating value, Btu/lb
qtotal	=	calculated total Plant fuel gas mass flow, lb/h

3.5.1.3 Evaporative Cooler Effectiveness

Determination of evaporative cooler effectiveness will not be required for the Heat Rate Test. Instead, temperature corrections to the Combustion Turbine will be based on the actual measured Combustion Turbine compressor inlet temperature compared to the Base Reference Compressor Inlet Temperature.

Exhibit 4.2-17

3.5.2 Fundamental Equations - Corrections

The following fundamental equations for performance corrections are based on Section 5 of PTC 46.

3.5.2.1 Corrected Net Plant Output

The calculation of corrected Net Plant Output is as follows:

(P_meas - ∆₁)

P_corr = ___________

Παi

where:

 

P_corr = corrected Net Plant Output, kW

∆_{1 =} correction (STG only) to power for ambient wet bulb temperature, kW

 

α₁ = correction to power for compressor inlet temperature

 

α₂ = correction to power for barometric pressure

 

α₃ = correction to power for compressor inlet relative humidity

3.5.2.2 Corrected Net Plant Heat Rate

The calculation of corrected Net Plant Heat Rate is as follows:

Q_meas

HR_corr = _____________

P_corr Π β_i

where:

 

HR_corr = corrected Net Plant Heat Rate, Btu/kWh (HHV)

 

β 1 = correction to fuel consumption for compressor inlet temperature

 

β 2 = correction to fuel consumption for barometric pressure

 

β 3 = correction to fuel consumption for compressor inlet relative humidity

3.5.3 Correction Factor Equations

The following correction curves, to be provided in APPENDIX D, will provide the equations and the correction factors to use in the above correction equations. Note that the ∆_i correction is additive in units of kW, while a_i and ß_i corrections are multiplicative and are dimensionless.

The correction curves will be developed by the contractor under the EPC Agreement using a

Exhibit 4.2-18

thermal performance modeling program. The thermal model incorporates as-purchased performance data provided by the manufacturers for all major pieces of equipment including Combustion Turbines, Steam Turbines, HRSGs, condenser, cooling tower, fuel gas heaters, boiler feed pumps, condensate pumps, circulating water pumps and piping systems. Gulf Power will have the right to verify curve derivations.

A correction curve will be created for a particular parameter by varying that parameter across the applicable range while holding all other parameters constant. For example, the correction for barometric pressure will be developed by running the model at various barometric pressures while holding constant the compressor inlet temperature, ambient wet bulb temperature, etc. A number of data points will be selected across the range as required to obtain a tight data regression fit.

3.5.3.1 Ambient Wet Bulb Temperature Corrections

The correction to Net Plant Output for ambient wet bulb temperature is given as shown in the test results.

3.5.3.2 Compressor Inlet Temperature and Relative Humidity Corrections

The corrections to Net Plant Output and Fuel Consumption for compressor inlet temperature are given as shown in the test results. The corresponding corrections for compressor inlet relative humidity are given as shown in the test results.

3.5.3.3 Barometric Pressure Corrections

The corrections to Net Plant Output and Fuel Consumption for barometric pressure are given as shown in the test results.

3.6 Test Results

After completion of the test calculations, the corrected results of the two one-hour test periods will be averaged to determine the overall corrected Tested Heat Rate (THR). The corrected Tested Heat Rate will be used as outlined in Section 8.3 of the Agreement to determine what Heat Rate Payments, if any, shall be made by either Party.

3.7 Test Measurement Uncertainty

Test measurement uncertainty will not be applied to the results of the Heat Rate Test.

3.8 Test Report

A written test report will document the results of the test and be provided to Gulf Power. The report of results for the Heat Rate Test will be incorporated into the overall Annual Plant Test Report. The following items will be included as a minimum.

• Date and time of test start and finish

• Description of the test operating and meteorological conditions

• Description of any temporary instrumentation used in the test

• Operator log sheets indicating any abnormal occurrences

• Instrument calibration data

• Raw test data

• Test calculations

• Test results

Exhibit 4.2-19

• Factored Fired Hours for each Combustion Turbine (at beginning and end of test)

4.0 Capacity Tests

Two Capacity Tests will be conducted without Power Augmentation (Capacity Test 1) and with Power Augmentation (Capacity Test 2) to determine the maximum Net Plant Output for the purposes of establishing the Contract Capacity for the Plant and the Power Augmentation Capacity (PAC) of each Combustion Turbine as outlined in Sections 4.2 and 4.3 of the Agreement. Each test will consist of two (2) one-hour test periods. Capacity Test 1 will follow the Heat Rate Test. Capacity Test 2 will follow Capacity Test 1. A new operating configuration will be established with a one-hour stabilization period recommended prior to each test. If ambient conditions are acceptable, both tests will include a Combustion Turbine Evaporative Cooler Test (see Note 2 Table 2-1).

The Capacity Tests will be conducted in general accordance with PTC 46 using an overall Plant test concept. Corrections will be applied to measured test results to account for variations in the Base Reference Conditions (Table 2-1) such as ambient temperature and barometric pressure. No test measurement uncertainties will be applied to the corrected test parameters in the determination of test results. The following sections provide the general procedures for setup and execution of the tests and for determining test results.

4.1 Division of Responsibilities

This section describes the division of responsibilities in the preparation and conduct of the Capacity Tests.

4.1.1 Shell Responsibilities

The responsibilities of Shell prior to, during, and after the tests include the following.

• Cause Owner to prepare detailed test procedures to govern the conduct of the performance test.

• Cause Owner to determine procedures for data acquisition, data backup, and methods of data analysis.

• Cause Owner to determine parameters to be manually collected and recorded.

• Cause Owner to ensure that the distributed control system (DCS) data collection is operational and the archival deadbands have been properly established prior to commencement of testing.

• Cause Owner to coordinate test setup and calibration activities.

• Cause Owner to conduct any necessary pre-tests.

• Cause Owner to verify that major equipment operates at or near design conditions at steady state.

• Cause Owner to ensure that permanent and temporary instrumentation required for the tests and for proper operation/control of the Plant is properly installed, calibrated, and operating.

• Provide instrument calibration records to Gulf Power.

• Provide proper notice to Gulf Power of the intended test schedule.

• Cause Owner to provide personnel to collect test data as necessary.

• Cause Owner to designate a Performance Test Director (PTD) with the overall responsibility for the direction and conduct of the tests.

• Cause Owner to provide technical direction to the operators throughout the test.

• Cause Owner to establish and report auxiliary loads in service and valve position lineups during the test.

• Cause Owner to manage the collection of test data.

Exhibit 4.2-20

• Cause Owner to calculate specified performance parameters from measured test data.

• Cause Owner to perform calculations to adjust test results to the Base Reference Conditions.

• Prepare and submit a complete test report.

4.1.2 Gulf Power Responsibilities

The responsibilities of Gulf Power prior to, during, and after the tests include the following.

• Arrange for the transmission of power downstream of the Energy Point of Delivery.

• Arrange for adequate supply of Gas according to the Agreement.

• Designate representatives to witness tests.

• Provide approval of test results within a reasonable time.

4.2 Test Conditions

The following sections describe the test conditions including the general operating conditions, the test boundary, test prerequisites, and the cycle valve lineup for the test.

4.2.1 General Test Conditions

• Base Reference Conditions are listed in Tables 2-1 through 2-3.

• The project design heat balances are provided in APPENDIX A.

• The tests will be conducted in accordance with this document which is agreed upon by the Shell, the Owner and Gulf Power. Conflicts in test methods will be resolved using the following order of precedence.

1. Sections 1, 2, and 4 of this Exhibit 4.2

2. ASME PTC 46

• If test conditions differ from those indicated in Table 2-1, corrections will be calculated and applied to test data in accordance with the methods outlined in Section 4.5.

• All air, steam, water, and generator conditions which have an effect on the data collected for the determination of the corrected test results will be regulated as near as possible to the conditions indicated in the Project Heat Balances corresponding with the expected performance levels. OEM requirements for continuous and long-term operation, such as Steam Turbine inlet temperature and Combustion Turbine base load control curve, will not be exceeded.

• The Plant will be operated from the control room with systems operating in automatic mode which are normally operated in automatic mode, and in a manner consistent with Prudent Generator Practices for continuous and long-term operation.

• For conditions beyond the control of Shell, the Owner or Gulf Power, reasonable efforts will be made to conduct the tests as close as possible to the Base Reference Conditions to minimize the magnitude of the applied correction factors, subject to the requirements of Part A of this Exhibit 4.2.

• The HRSGs will be operated with HRSG blowdown as necessary. No corrections for blowdown will be applied.

• Reasonable efforts will be made to conduct the tests with all Plant components in a clean and undamaged condition.

• Evaporative coolers will be in service if ambient dry bulb temperature is 60° F or greater, and if the wet bulb depression is at least 10° F. (See Note 2 Table 2-1).

4.2.2 Test Timing

Exhibit 4.2-21

The two Capacity Tests will each consist of two (2) one-hour test periods following an estimated one-hour stabilization period. The tests will normally be performed after completion of the Heat Rate Test. The test will be scheduled according to the requirements of Sections 4.2 and 4.3 of the Agreement. The tests will be conducted after any pretests required by the Owner.

The two (2) one-hour test runs associated with each Capacity Test will be continuous, provided steady state conditions are maintained. If steady state conditions cannot be maintained, the test will be suspended until steady conditions return. When steady state conditions return the test may be resumed.

Preliminary performance testing may be conducted and the resulting data analyzed prior to the actual test at the discretion of the Owner. Preliminary testing may be used for checking the operation and readings of all instruments directly related to the test and for the training of observers and other test personnel. Data will be collected and evaluated during preliminary testing to determine if abnormalities exist with the test data.

4.2.3 Test Prerequisites

Prior to conducting a test, a number of prerequisites must be fulfilled to ensure the Plant is in test-ready condition. Some of these activities are optional based on the number of operating hours on the equipment and based on the history of operation during the commissioning process. Shell may add or delete from this list as appropriate.

• Pre-operational testing and normal startup procedures will be completed.

• All permanent and temporary instrumentation required for the test will be calibrated, installed and a loop checked. DCS and test data acquisition system (DAS) configurations and ranges will be verified.

• Calibrations for temporary test instrumentation will be current. Plant instruments for primary measurements will be zero and span checked as appropriate.

• DCS data logs will be setup and verified to collect primary and secondary data.

• The local inlet guide vanes (IGVs) position indicators and control system IGV indications will be checked for correspondence and that they correctly indicate full open position.

• The accuracy and calibration of the compressor discharge pressure measurements which are used to control the Combustion Turbines at base load will be confirmed.

• It will be verified that the proper Combustion Turbine base load exhaust temperature control algorithm is input into the control system and is operating properly (confirm that a commissioning curve which results in lower than base load turbine inlet temperatures is not being used).

• The Combustion Turbine compressor, inlet scroll, and IGVs will be cleaned and inspected. This will be done with an offline compressor water/detergent wash.

• The Combustion Turbine fuel nozzles may be removed and visually inspected if deemed necessary by Owner.

• Throttle valves may be inspected, cleaned, and/or adjusted to achieve design tolerances if deemed necessary by Owner.

• The Combustion Turbine inlet air filter system cleanliness will be verified by visual inspection and pressure drop measurement.

• Preliminary test data will be analyzed to identify incorrect readings or incorrect operating modes and to assess the actual performance characteristics of all major equipment throughout the cycle.

• Condenser pressure measurements will be compared for consistency and for reasonable correspondence with condensate temperatures. Vacuum pressure transmitter legs will be evacuated prior to testing to eliminate any possible water leg buildup.

• Control system tuning will be complete to provide reasonably dampened drum level and flow oscillations. Gas supply pressure to the Combustion Turbines will be reasonably stable.

Exhibit 4.2-22

• Water legs on pressure measurements and any vertical flow measurements will be documented.

• Primary flow elements may be inspected, where possible, and configuration of the flow metering systems documented.

• Preliminary tests may be run as necessary to confirm any of the above information.

• The startup and operations personnel will be familiar with the valve position lineups and auxiliary load lineups for the test, as described in the following sections. The time required to complete the isolations should be determined.

• Personnel required to collect any manual test data and fuel samples will be identified by the Owner and trained by the PTD.

4.2.4 Valve Position Lineups

During a test, the valve position lineups will be in the normal operating position. HRSG and Steam Turbine bypasses, drains, and vents should be isolated to the fullest extent possible. Cascading, continuous, and intermittent blowdown valves will be in the normal operating position as required. Automatic valves will remain in their normal mode of operation.

Leakages and seepages should be identified in all main system valves, and Shell shall cause Owner to utilize reasonable efforts to minimize these cycle losses. The safe and prudent operation of the Plant will not be compromised to minimize cycle losses during a test.

4.2.5 Auxiliary Load Status

The auxiliary loads in service during a test will be established as the loads required to sustain continuous safe operation of the Plant. The expected operating status of major equipment is indicated in Table 2-3. Deviations from this list may be necessary or beneficial and will be documented prior to test commencement. Redundant loads, such as some HVAC, pumps, and vapor extractors, will not be in service. No corrections will be applied for auxiliary loads in service unless deemed appropriate.

4.2.6 Pre-Test Activities

Prior to initiating a test, the following activities must take place.

• Confirmation that the General Test Conditions and Test Prerequisites, as listed above, have been observed or will be obtained.

• A pre-test meeting will be held to assign test personnel and specific test responsibilities.

• A walkdown of the Plant will be conducted to familiarize test personnel with the location of equipment, instrumentation, etc. Watches will be synchronized with the indicated DCS time.

• The Combustion Turbines will be set to base load exhaust temperature control, and will be automatically controlled in a manner to simulate the heat balances in accordance with Table 2-1.

1. The Plant will be operated by the Owner’s operations staff under the direction of the PTD.

• Once base load is attained, the Plant will be allowed approximately one hour to reach steady state operation. Steady state is defined as follows:

1. The average Combustion Turbine exhaust temperature does not vary more than 5° F in fifteen minutes.

2. The Steam Turbine output does not vary more than 500 kW in fifteen minutes.

Outside influences such as ambient conditions will be monitored to ensure minimum variations in accordance with PTC 22, 6, and 4.4. However, exceedances of these specified

Exhibit 4.2-23

variations will not invalidate a test.

• Instrumentation status will be checked including operation of the test data acquisition system (DAS).

• Valve position lineups will be verified.

• Auxiliary loads in service will be documented.

• Agreed deviations from the established procedures will be documented.

• Communications will be verified as necessary between the control room and the test personnel in the field. The PTD will ensure that all test personnel have been briefed and are on station with appropriate data forms and equipment.

• The PTD will announce the test start to all personnel.

4.2.7 Post-Test Activities

The following activities will take place at the conclusion of the test period.

• The PTD will announce the test end to all personnel.

• The test data will be collected and compiled.

• A copy of the compiled test data will be provided to Gulf Power.

• Copies of operator logs, chemistry logs, alarms, and equipment status changes during the test period will be provided to the PTD.

• Final test results will be provided in the Test Report.

4.3 Test Data Requirements

The following test data requirements will be observed for the tests.

4.3.1 Data Collection

Data collected during a test may include any of the following.

• Data from Plant DCS.

• Data from test data acquisition system (DAS).

• Manually collected data.

The test DAS will be used to collect data from any temporary test instruments. The Plant DCS will collect the remainder of the data including fuel gas parameters and net electrical output as well as all secondary measurements collected for information only. Some manual data may be collected as deemed necessary by the PTD. Copies of all raw data will be made available at the conclusion of the test for review.

Any manual data will be collected on intervals no greater than ten minutes. All electronically collected parameters will be scanned and logged as snapshots or rolling averages on intervals no greater than one minute to minimize precision error.

4.3.2 Data Elimination

Certain test conditions may require elimination of specific sets of data during the evaluation of test results. Depending on the circumstances, the test may be suspended, restarted, or the total test duration reduced. The following periods may be eliminated from consideration in the determination of test results as mutually agreed upon by Shell, the Owner and Gulf Power.

• Periods when fuel parameters are outside the range of the Combustion Turbine manufacturer’s specifications.

Exhibit 4.2-24

• Periods when parameters outside the control of Owner exhibit fluctuations in excess of the recommended allowable fluctuations as determined by the PTD.

• Periods when a Plant component trips but does not cause a generator trip.

• Periods when steady state conditions are not maintained.

4.3.3 Data Reduction

Raw data will be collected for each one-hour test period and averaged. Data reduction periods will not exceed one hour to minimize the impact of varying ambient conditions. Test calculations will be performed on a one-hour basis. Some raw data may include corrections for instrument laboratory calibration data if the corrections can be performed automatically in the DCS or DAS.

4.3.4 Quality Assurance

Shell shall cause all raw data and reduced data will be controlled and maintained by the Owner. Copies of all raw data will be made available to the Parties at the conclusion of the tests. Shell shall ensure that all recorded data is accurate and complete, and maintained by Owner for future analysis.

4.4 Measurements and Instrumentation

A list of test measurement points and a corresponding test point diagram will be provided in APPENDIX C. The list and diagram summarize all measurements that will be taken during the test including measurements for the calculation of test results, backup measurements, and measurements allowing for the evaluation of individual Plant component performance. The following sections describe the selection of these instruments.

4.4.1 Instrument Selection

Test measurements will be generally based on the use of Plant instrumentation. However, for certain parameters that have high sensitivity coefficients to the calculated test results, precision test instrumentation will be used in accordance with PTC 46. Owner reserves the right to substitute precision test instrumentation in place of any Plant instrumentation to minimize the test measurement uncertainty and improve the confidence in test results. The instrumentation will be selected and calibrated in order to ensure that the overall test uncertainties are less than or equal to the default values.

4.4.2 Calibration Requirements

Shell shall ensure that the Owner will provide current calibration records and/or factory certifications, traceable to appropriate standards, for all instrumentation critical to the calculation of test results (Class 1 primary variables) in accordance with PTC 46. Calibrations may take place at the Plant Site or at an independent instrumentation laboratory. Permanent Plant thermocouples which are wired to cold junctions in the DCS cabinets will provide “type” measurements and generally will not be calibrated. Calibration laboratories will be certified, traceable to nationally respected standards, and will maintain proper quality assurance procedures. Recalibration of test instruments after the tests will not be required unless, by mutual agreement between the Shell, the Owner and Gulf Power, there is cause for concern regarding instrumentation drift during the testing program.

4.4.3 Redundancy

Redundant measurements will be collected by the DCS where available to facilitate detection of instrument reading errors and to provide backup measurements in case of on-line device or signal

Exhibit 4.2-25

malfunctions during the test. If during a test period, or during the evaluation of the data after the test, obvious errors are found in the recorded data, those readings will be disregarded. The test period would be considered valid provided the available backup data is considered to be correct at the discretion of the Owner.

4.4.4 Primary Variables

Measurements that are used in the calculation of test results are considered primary variables. They are further classified as Class 1 or Class 2 primary variables. Class 1 variables are those which have relative sensitivity coefficients of 0.2 or greater. Instruments for the primary variables were selected in accordance with PTC 46 requirements as presented in the following sections.

4.4.4.1 Electrical Power Measurements

The Net Plant Output is equivalent to the power delivered to the high voltage side of the four generator stepup transformers (GSUs). The as-tested Net Plant Output will be determined as the measured power to Alabama Power Company.

Power to Alabama Power Company (APC) will be measured with an APC supplied revenue quality (0.1%) power meter located in the switchyard control building. The associated metering PTs and CTs are specified as ANSI accuracy class [0.3% and 0.15%], respectively. The meter includes real time analog output MWh and MVAR signals to the DCS. The DCS values will be used as the primary measurement for test calculations. Local manual readings may be recorded as primary or secondary measurements at the Owner’s discretion.

As secondary net power measurements, there are watt/VAR transducers on the high voltage side of each of the four GSUs which provide analog signals to the DCS. The sum of these readings should be equivalent to the sum of the utility meter.

Combustion Turbine and Steam Turbine generator power output will be measured by watt/VAR transducers (0.2%) located at the terminals of each generator. Data will be collected electronically by the DCS via datalink with the Mark V. As a check, net power can be calculated as the sum of the four generator meters, less the AUX transformer meters, less the AUX transformer losses, less generator excitation, less GSU transformer losses.

For the measurement of Plant auxiliary loads, a secondary measurement, kW and kVAR will be determined at the low voltage side of each of the auxiliary (AUX) transformers. I/O points for these readings may need to be configured in the field.

CTG auxiliary loads will be determined manually from generator panel meters. CTG excitation power will be calculated from DC field volts and amps recorded in the DCS.

Any manual readings of megawatt hours (MWh) will be recorded approximately every 10 minutes. The average MW delivered for an hour will be the difference in the readings at the end and beginning of the hour divided by the precision time duration between readings.

4.4.4.2 Ambient Conditions Measurements

Ambient conditions will be measured by precision test instrumentation with outputs collected by the test DAS. Laboratory calibrations will verify instruments are within the required accuracies.

Ambient dry bulb temperature at each Combustion Turbine inlet will be measured using an array of nine 100-ohm platinum RTDs mounted upstream of the evaporative cooler, but shielded from solar radiation.

Ambient wet bulb temperature at each Combustion Turbine inlet will be measured with a mechanically aspirated psychrometer located near each Combustion Turbine inlet. Relative humidity will be calculated in accordance with [16].

Compressor inlet temperature will be measured with a minimum of 4 calibrated 100-ohm platinum RTDs mounted inside the inlet duct upstream of the IGVs. Compressor inlet humidity will be calculated

Exhibit 4.2-26

based on the measured ambient wet bulb temperature.

Barometric pressure will be measured with a calibrated digital barometer or absolute pressure transmitter mounted in the vicinity of the Combustion Turbine inlet with proximity to the Combustion Turbine centerline elevation.

Ambient wet bulb temperature at the cooling tower will be measured with a minimum of two mechanically aspirated psychrometers located in the vicinity of the cooling tower.

4.4.4.3 Steam Turbine Measurements

Steam Turbine exhaust pressure will be measured with the three GE supplied basket tips with pressure transmitters installed in the turbine exhaust hood. The two Owner supplied transmitters on the condenser neck will serve as secondary measurements.

Steam Turbine throttle pressure will be measured with the three GE supplied transmitters on the main steam header.

4.4.5 Secondary Variables

Secondary variables are those measurements not directly used in the calculation of test results. These variables will be measured to provide backup readings for the primary variables, to allow Owner to establish complete heat balance calculations around the cycle and individual Plant components, and to provide assistance in pinpointing any improper test operating condition. Secondary variables will generally be permanent Plant instrumentation. However, Owner may choose to install a number of temporary test instruments to achieve more accurate results in evaluating individual component performance.

4.5 Test Calculations

To evaluate the measured test data against the expected performance levels, a number of calculations must be performed. First, the collected data is averaged for each one-hour test period. Then, the as-tested gross electrical output and auxiliary consumption are determined. Next, the gross Combustion Turbine output and Steam Turbine output are corrected to Base Reference Conditions using the correction curves to be provided in APPENDIX D. The corrected Net Plant Output is then determined as the sum of the corrected Combustion Turbine and Steam Turbine outputs less the auxiliary consumption. The results of the test will be determined as the average of the two sets of corrected Net Plant Output values.

The fundamental equations to perform the test calculations are laid out in the following sections. These equations, based on PTC 46, explain how to arrive at the corrected Plant performance using the correction curves from APPENDIX D. A sample calculation will be provided in APPENDIX E.

4.5.1 Fundamental Equations - Measurements

4.5.1.1 As-Tested Electrical Measurements

The calculation of as-tested Net Plant Output is as follows:

Pnet	=	PAPC
Pgross	=	PCT1 + PCT2 + PCT3 + PST
Paux	=	Pgross - Pnet
where:

Exhibit 4.2-27

Pnet	=	as-tested Net Plant Output, kW
PAPC	=	measured power delivered to Alabama Power Company, kW
Pgross	=	as-tested gross Plant output, kW
PCti	=	measured Combustion Turbine gross output (i = 1 to 3), kW
PST	=	measured Steam Turbine gross output, kW
Paux	=	calculated auxiliary consumption

4.5.1.2 As-Tested Evaporative Cooler Effectiveness and Reference CIT

The calculation of as-tested Evaporative Cooler Effectiveness and Base Reference Compressor Inlet Temperature are as follows:

X =

DB_T – CIT_T

__________________

DB_T – WB_T

CIT_RC = DB_RC – X(DB_RC – WB_RC) = 99 – 23X

where:
X	=	tested evaporative cooler effectiveness
DB	=	ambient dry bulb temperature, F
CIT	=	compressor inlet temperature, F
WB	=	ambient wet bulb temperature, F
T	=	subscript indicating test conditions
RC	=	subscript indicating base reference conditions

4.5.2 Fundamental Equations - Corrections

The following fundamental equations for performance corrections are based on Section 5 of PTC 46.

4.5.2.1 Corrected Net Plant Output

The calculation of corrected Net Plant Output is as follows:

Exhibit 4.2-28

P_corr = ΣP_CTicorr + P_STcorr = P_aux

where:
Pcorr	=	corrected Net Plant Output, kW
PCTicorr	=	corrected gross Combustion Turbine output (i = 1 to 3), kW
PSTcorr	=	corrected gross Steam Turbine output, kW

4.5.2.2 Corrected Gross CTG Output

The calculation of corrected gross Combustion Turbine output is as follows:

P_CTicorr =

P_CTi

________________

α_CT1α_CT2α_CT3

where:
PCTcorr	=	corrected gross Combustion Turbine output, kW
αCT1	=	correction to Combustion Turbine power for compressor inlet temperature
αCT2	=	correction to Combustion Turbine power for barometric pressure
αCT3	=	correction to Combustion Turbine power for gas turbine power augmentation stream
i	=	subscript indicating Combustion Turbine Generating Unit 1, 2, or 3

4.5.2.3 Corrected Gross STG Output

The calculation of corrected gross Steam Turbine output is as follows:

P_STcorr = P_ST - ∆_ST1

where:
PSTcorr	=	corrected gross Steam Turbine output, kW
∆ST1	=	correction to Steam Turbine power exhaust pressure, kW

4.5.3 Correction Factor Equations

The following correction curves, to be provided in APPENDIX D, will provide the equations and the correction factors to use in the above correction equations. Note that the ∆_i corrections are additive in units of kW, while a_i and ß_i corrections are multiplicative and are dimensionless. The correction curves are based on Combustion Turbine and Steam Turbine correction curves provided by GE.

Exhibit 4.2-29

4.5.3.1 Compressor Inlet Temperature

The corrections to gross Combustion Turbine output for compressor inlet temperature are given as shown in the test results.

4.5.3.2 Barometric Pressure Corrections

The corrections to gross Combustion Turbine output for barometric pressure are given as shown in the test results.

4.5.3.3 Power Augmentation Corrections

The corrections to gross Combustion Turbine output for degradation, to be applied for operation exceeding 150 fired hours are as shown in test results.

4.5.3.4 STG Corrections

The corrections to Steam Turbine output for LP turbine exhaust pressure is given as shown in test results.

4.6 Test Results

After completion of the test calculations, the corrected results of the two one-hour test periods will be averaged to determine the overall corrected result for each of the two Capacity Tests. The final test results for Capacity Test 1 and Capacity Test 2 will each be rounded to the nearest 100 kW. The corrected results of Capacity Test 2 will be used to establish Contract Capacity as outlined in Sections 4.2 and 4.3 of the Agreement. The corrected results of Capacity Test 1 will be subtracted from the corrected results of Capacity Test 2 to determine the amount of Tested Plant Power Augmentation Capability. This in turn will be used to determine the Power Augmentation Capacity (PAC) of each Combustion Turbine as outlined in Section 1 and Sections 4.2 and 4.3 of the Agreement.

4.7 Test Measurement Uncertainty

Test measurement uncertainty will not be applied to the results of the Capacity Tests.

4.8 Test Report

A written test report will document the results of the tests and be provided to Gulf Power. The report of results for the Capacity Tests will be incorporated into the overall Annual Plant Performance Test Report. The following items will be included as a minimum.

• Date and time of test start and finish

• Description of the test operating and meteorological conditions

• Description of any temporary instrumentation used in the test

• Operator log sheets indicating any abnormal occurrences

• Instrument calibration data

• Raw test data

• Test calculations

• Test results

Exhibit 4.2-30

APPENDIX A

PROJECT HEAT BALANCES

	Summary		Case Description (New and Clean Performance)
			Case 1	Case 2	Case 3	Case 4	Case 5	Case 6
Ambient Temperature			[**]	[**]	[**]	[**]	[**]	[**]
Number of CTG/HRSG Units Operating			3 CT's @ 100%	3 CT's @ 100%	3 CT's @ 100%	3 CT's @ 100%	3 CT's @ 100%	3 CT's @ 100%
Fuel Type			Natural Gas	Natural Gas	Natural Gas	Natural Gas	Natural Gas	Natural Gas
Fired to OP			Yes	Yes	Yes	Yes	Yes	Yes
Power Augementation						Yes	Yes	Yes
CTG Model			[**]	[**]	[**]	[**]	[**]	[**]
CTG Load Level (percent of base load)			100%	100%	100%	100%	100%	100%
CTG Evaporative Cooler			On	On	Off	On	On	Off
STG Throttle Conditions		psia / F	[**]	[**]	[**]	[**]	[**]	[**]
STG Hot Reheat Conditions		psia / F	[**]	[**]	[**]	[**]	[**]	[**]
Condenser Pressure			[**]	[**]	[**]	[**]	[**]	[**]
Gross CTG Output		kW (each)	[**]	[**]	[**]	[**]	[**]	[**]
		kW (total)	[**]	[**]	[**]	[**]	[**]	[**]
STG Output		kW	[**]	[**]	[**]	[**]	[**]	[**]
Gross Plant Output		kW	[**]	[**]	[**]	[**]	[**]	[**]
Auxiliary Power/Losses		kW	[**]	[**]	[**]	[**]	[**]	[**]
Net Plant Output		kW	[**]	[**]	[**]	[**]	[**]	[**]
Gross CTG Heat Rate		Btu/kWh (LHV)	[**]	[**]	[**]	[**]	[**]	[**]
		Btu/kWh (HHV)	[**]	[**]	[**]	[**]	[**]	[**]
Duct Burner Heat Input (total)		MBtu/h (LHV)	[**]	[**]	[**]	[**]	[**]	[**]
		MBtu/h (HHV)	[**]	[**]	[**]	[**]	[**]	[**]
		% of GPO	[**]	[**]	[**]	[**]	[**]	[**]
Total Plant Heat Input		MBtu/h (LHV)	[**]	[**]	[**]	[**]	[**]	[**]
		MBtu/h (HHV)	[**]	[**]	[**]	[**]	[**]	[**]
Gross CTG Heat Rate		Btu/kWh (LHV)	[**]	[**]	[**]	[**]	[**]	[**]
		Btu/kWh (HHV)	[**]	[**]	[**]	[**]	[**]	[**]
Net Plant Heat Rate		Btu/kWh (LHV)	[**]	[**]	[**]	[**]	[**]	[**]
		Btu/kWh (HHV)	[**]	[**]	[**]	[**]	[**]	[**]
Net Plant Efficiency		(LHV)	[**]	[**]	[**]	[**]	[**]	[**]
		(HHV)	[**]	[**]	[**]	[**]	[**]	[**]

Exhibit 4.2 Appendix A-1

Combustion Turbine (per unit)		Case Description (New and Clean Performance)
		Case 1	Case 2	Case 3	Case 4	Case 5	Case 6
Ambient Conditions:	Dry Bulb Temp, F	[**]	[**]	[**]	[**]	[**]	[**]
	Wet Bulb Temp, F	[**]	[**]	[**]	[**]	[**]	[**]
	Pressure, psia	[**]	[**]	[**]	[**]	[**]	[**]
	Relative Humidity	[**]	[**]	[**]	[**]	[**]	[**]
Compressor Inlet Conditions	Temp. F	[**]	[**]	[**]	[**]	[**]	[**]
	Relative Humidity	[**]	[**]	[**]	[**]	[**]	[**]
Evaporative Cooler Status		[**]	[**]	[**]	[**]	[**]	[**]
Fuel Consumption	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	MBtu/h (LHV)	[**]	[**]	[**]	[**]	[**]	[**]
	MBtu/h (HHV)	[**]	[**]	[**]	[**]	[**]	[**]
Fuel Heating Value	LHV	[**]	[**]	[**]	[**]	[**]	[**]
	HHV	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
Water Injection	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
Steam Injection	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
Exhaust Gas	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Temp. , F	[**]	[**]	[**]	[**]	[**]	[**]
Generator Gross Output	kW	[**]	[**]	[**]	[**]	[**]	[**]

Exhibit 4.2 Appendix A-2

Heat Recovery Steam Generator (per unit)		Case Description (New and Clean Performance)
		Case 1	Case 2	Case 3	Case 4	Case 5	Case 6
HP Superheater Outlet	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	psia	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
	Enthalpy, Btu/lb	[**]	[**]	[**]	[**]	[**]	[**]
HP Steam Desuperheating Spray	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
	% of outlet steam	[**]	[**]	[**]	[**]	[**]	[**]
HP Drum Blowdown	% of feedwater	[**]	[**]	[**]	[**]	[**]	[**]
Feedwater to HP Economizer	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Pressure, psia	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
Duct Burner Inlet Temperature	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
Duct Burner Outlet Temperature	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
Hot Reheat Steam	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Pressure, psia	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
	Enthalpy, Btu/lb	[**]	[**]	[**]	[**]	[**]	[**]
Reheat Desuperheater Spray	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
	% of steam flow	[**]	[**]	[**]	[**]	[**]	[**]
Reheater Inlet Steam (includes IP)	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Pressure, psia	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
	Enthalpy, Btu/lb	[**]	[**]	[**]	[**]	[**]	[**]

Exhibit 4.2 Appendix A-3

Heat Recovery Steam Generator (per unit)		Case Description (New and Clean Performance)
		Case 1	Case 2	Case 3	Case 4	Case 5	Case 6
Cold Reheat Steam from STG	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Pressure, psia	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
	Enthalpy, Btu/lb	[**]	[**]	[**]	[**]	[**]	[**]
IP Steam to Cold Reheat	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Pressure, psia	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
	Enthalpy, Btu/lb	[**]	[**]	[**]	[**]	[**]	[**]
IP Drum Blowdown	% of feedwater	[**]	[**]	[**]	[**]	[**]	[**]
Fuel Gas Heating Water	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
(from IP economizer outlet)	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
Feedwater to IP Economizer	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Pressure, psia	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
LP Superheater Outlet	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Pressure, psia	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
	Enthalpy, Btu/lb	[**]	[**]	[**]	[**]	[**]	[**]
LP Drum Blowdown	% of feedwater	[**]	[**]	[**]	[**]	[**]	[**]
LP Economizer Inlet	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
Preheater Recirculation	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
Fuel Gas Heating Water Return	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
Condensate	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
Stack Exhaust	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]

Exhibit 4.2 Appendix A-4

Steam Turbine Generator		Case Description (New and Clean Performance)
		Case 1	Case 2	Case 3	Case 4	Case 5	Case 6
Throttle Conditions	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Pressure, psia	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
	Enthalpy, Btu/lb	[**]	[**]	[**]	[**]	[**]	[**]
Cold Reheat Steam	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Pressure, psia	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
	Enthalpy, Btu/lb	[**]	[**]	[**]	[**]	[**]	[**]
Reheat Flow Added in HRSGs	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
Reheat Pressure Drop	psi	[**]	[**]	[**]	[**]	[**]	[**]
	%	[**]	[**]	[**]	[**]	[**]	[**]
Hot Reheat Steam	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Pressure, psia	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
	Enthalpy, Btu/lb	[**]	[**]	[**]	[**]	[**]	[**]
LP Admission Steam Temperature Differential		[**]	[**]	[**]	[**]	[**]	[**]
LP Admission Steam	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Pressure, psia	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
	Enthalpy, Btu/lb	[**]	[**]	[**]	[**]	[**]	[**]
LP Turbine Exhaust	Flow, lb/h	[**]	[**]	[**]	[**]	[**]	[**]
	Pressure, in HgA	[**]	[**]	[**]	[**]	[**]	[**]
	Temperature, F	[**]	[**]	[**]	[**]	[**]	[**]
	Enthalpy, Btu/lb	[**]	[**]	[**]	[**]	[**]	[**]
Generator	Output, kW	[**]	[**]	[**]	[**]	[**]	[**]
Condenser Duty	Heat Duty,MBtu/h	[**]	[**]	[**]	[**]	[**]	[**]

Exhibit 4.2 Appendix A-5

APPENDIX B

VALVE POSITION LINEUPS

[Chart 1]

[Chart 2]

[Chart 3]

[Chart 4]

Exhibit 4.2 Appendix B

APPENDIX C

TEST MEASUREMENT POINTS

Exhibit 4.2 Appendix C

TENASKA CENTRAL ALABAMA GENERATING STATION

TEST MEASUREMENT POINTS

1. Temporary Instruments

Dry bulb temperature.

Four laboratory calibrated 4-wire 100ohm platinum RTDs will be used to measure ambient dry bulb temperature in each gas turbine inlet filter house. Twelve RTDs total.

GT Compressor Inlet Temperature.

Six laboratory calibrated 4-wire 100ohm platinum RTDs will be used to measure ambient wet bulb temperature in each gas turbine filter house. The RTDs will be used in conjunction with two mechanically aspirated psychrometers. Two instruments will be located in each GT filter inlet house.

Six psychrometers total.

Barometric Pressure.

Two laboratory calibrated Rosemount 3051 absolute pressure transmitters will be used to measure ambient barometric pressure. The transmitters will be located on the hand rail outside the GT1 generator exciter compartment.

Cold Circulating Water.

Two laboratory calibrated 4-wire 100ohm platinum RTDs will be used to measure the temperature of the cold circulating water leaving the cooling tower.

Hot Circulating Water.

Two laboratory calibrated 4-wire 100ohm platinum RTDs will be used to measure the temperature of the hot circulating water entering the cooling tower.

Condenser Pressure.

Three laboratory calibrated Rosemont 3051 absolute pressure transmitters will be used to measure condenser backpressure.

Plant Fuel Gas Office Plate differential Pressure.

One laboratory calibrated Rosemount model 3051 differential pressure transmitter will be used. The transmitter will be installed with temporary tubing that is installed into the station differential pressure transmitter manifold.

2. Instrument/Measurement Selection for all Tests:

Parameter	Instrument/Measurement
Net Power Plant	PAG Capacity Test: Manually recorded values of the Tenaska Backup Primary Net kWh Meter. Dry Capacity and Heat Rate Tests: Manually recorded values of APCO MWh Primary Meter. A stopwatch was used to measure the elapsed time between MWh pulses. Readings taken in the Tenaska (PAG Test) and the APCO Switchyard (Dry Capacity and Heat Rate Tests).
GT & STG Gross Power	The MkVI control system values of DWATT2 (Gas Turbine) and DWATT (Steam Turbine) will be used.

Exhibit 4.2 Appendix C

Compressor Inlet Temperature	See section titled “Temporary Instruments”
Filter Inlet (Ambient) Temperature	See section titled “Temporary Instruments”
Barometric Pressure	See section titled “Temporary Instruments”
Wet bulb Temperature	See section titled “Temporary Instruments”
Hot & Cold Circulating Water Temperature	See section titled “Temporary Instruments”
Condenser Pressure	See section titled “Temporary Instruments”
Fuel Gas Flow Rate Differential Pressure Static Pressure Flowing Temperature	Diff Pressure-See section titled “Temporary Instruments” Static Pressure-Station instrument FGSPT0101 Temperature-Station Instrument FGSTE0101
Fuel Gas Higher Heating Value	Southern Natural Gas chromatograph constituents stored in the Pi system. Transco chromatograph constituents stored in the Pi system.

Exhibit 4.2 Appendix C

APPENDIX D

CORRECTION CURVES

[**]

Exhibit 4.2 Appendix D

APPENDIX E

SAMPLE CALCULATION

[**]

EXHIBIT 5.2

ENERGY SCHEDULING PROCEDURES

AND PLANT RESPONSE CHARACTERISTICS

Energy Scheduling Procedures

1.         Requests for Energy covering one or more Days shall be made by Gulf Power to Shell in the form of Annex 5.2A no later than [**] covered by the Request for Energy. Any Request for Energy may be modified by Gulf Power by giving at least [**] notice to Shell in advance of the time the modification is to be implemented. Unless and until Gulf Power changes a Request for Energy, such Request for Energy shall remain in effect for the applicable Day(s) and each subsequent Day until Gulf Power changes the Request for Energy according to this Agreement; provided, however, if any Generating Unit shall have been taken off turning gear as provided on p. 8.4-4 of Exhibit 8.4, then any modification to a Request for Energy involving a Start of such Generating Unit shall provide Shell an additional [**] of the commencement of such Start. Each Day by no later than [**] Central Prevailing Time as part of its daily report of availability, Shell shall notify (which may be sent via e-mail) Gulf Power of the turning gear status of each Generating Unit for the next Day.

If any Request for Energy made through AGC would require a Start of a Generating Unit, operation of a Generating Unit below Minimum Load, the commencement of duct firing of a Generating Unit or the use of Power Augmentation in a Combustion Turbine, Shell shall as soon as practicable notify Gulf Power thereof and Shell shall cause Owner not to implement the Start, duct firing or Power Augmentation, or operate any Generating Unit below Minimum Load, without Gulf Power’s specific prior approval. Pending a response from Gulf Power, the Request for Energy shall be deemed to be reduced or increased, as the case may be, to the Request for Energy that could be in effect without resulting in a Start, duct firing, Power Augmentation or operation below Minimum Load.

To the extent that a Request for Energy not made through AGC would require the commencement of duct firing of a Generating Unit, Shell shall, as soon as practicable after it becomes aware that duct firing is likely to be required, notify Gulf Power thereof and to implement duct firing as necessary to meet such Request for Energy unless and until such Request for Energy is revised so that duct firing is not required. Notwithstanding the foregoing, to the extent that duct firing should not have been required, based on the Expected Non-Duct Fired Energy, to meet the applicable Request for Energy, the provisions of Section 5.6(c) of the Agreement shall apply.

To the extent that a Request for Energy not made through AGC would require the use of Power Augmentation in a Combustion Turbine, then unless such Request for Energy specifically directs that Power Augmentation be implemented, Shell shall, as soon as practicable after it becomes aware that Power Augmentation is likely to be required, notify Gulf Power thereof. If in response to such notice Gulf Power directs that Power Augmentation be used, Shell shall cause Owner to implement Power Augmentation to the extent necessary to meet such Request for Energy. If in response to such notice either (a) Gulf Power directs that Power Augmentation not be used or (b)

Exhibit 5.2-1

Gulf Power does not respond by the time that Power Augmentation would be required to be commenced in order to meet such Request for Energy, then the use of Power Augmentation will not be required , and Base Requested Energy may be reduced in accordance with the definition thereof. If Power Augmentation for a Combustion Turbine is used to meet a Request for Energy in the absence of a direction from Gulf Power to do so either in the Request for Energy or pursuant to the second sentence of this paragraph, the provisions of Section 5.6(b) of the Agreement shall apply regardless of whether Power Augmentation should have been required, based on the Expected Non-Power Augmentation Energy, to meet the applicable Request for Energy (and the use of Power Augmentation for such Combustion Turbine shall be treated as a Shell CTPA).

2.         The Parties shall work together to develop reliable procedures for Gulf Power to make Requests for Energy by telephone and other mutually acceptable electronic means. Each Party consents to the recording of conversations between the Parties’ respective personnel. Shell is entitled to rely upon and shall cause Owner to operate the Plant according to telephonic Requests for Energy that Shell reasonably believes in good faith to have been properly made by Gulf Power.

3.         No later than one Business Day after each Day within the Operating Term, Shell shall submit to Gulf Power a Confirmation Report in the form of Annex 5.2B. Gulf Power shall within two Business Days following receipt acknowledge such report by countersigning it and returning it to Shell, noting any disagreement Gulf Power may have with such Confirmation Report. If Gulf Power fails to acknowledge and return any Confirmation Report of Delivered Energy within the time frame indicated above, Gulf Power shall be deemed to have accepted the information contained in such Confirmation Report. Any acknowledgment by Gulf Power shall not restrict the Parties’ rights under Sections 9.3 and 9.5.

4.         In making a Request for Energy (including any modification), Gulf Power shall have the right to specify the Operating Configuration (as defined below) of the Plant that will be used to meet the Request for Energy, so long as the specified Operating Configuration is consistent with the Generating Unit Operating Principles taking into account any Outage. The Operating Configuration to be specified by Gulf Power shall be limited to determining:

(a) the number of Generating Units that are to be run;

(b) if the Plant is to be operated in AGC mode; and

(c) the number of Generating Unit(s), if any, that will operate with Power Augmentation.

provided that item (c) above shall not limit Shell’s right to cause Owner to use Power Augmentation to the extent provided in the fourth paragraph of Section 1 of this Exhibit 5.2.

Shell shall have the right to permit Owner to select which Combustion Turbine(s) will be operated in response to the Request for Energy, provided that such selection complies with Gulf Power’s specified Operating Configuration and with Prudent Generator Practices. Shell shall promptly notify Gulf Power of which Combustion Turbine(s) will be operated. If Gulf Power specifies an Operating Configuration that is inconsistent with the Generating Unit Operating

Exhibit 5.2-2

Principles or any Outage, Shell shall respond to the Request for Energy using an Operating Configuration that is as near as possible to the specified configuration and is consistent with the Generating Unit Operating Principles taking into account any Outage. If Gulf Power does not specify an Operating Configuration, Shell shall respond to the Request for Energy using the most efficient Operating Configuration, taking into account the Generating Unit Operating Principles and Prudent Generator Practices.

5.         Power Augmentation is not allowed to be placed in service on a Combustion Turbine unless (a) the Combustion Turbine is at baseload and fired on Gas, (b) the duct burner associated with the Combustion Turbine is in operation, and (c) the compressor inlet temperature of the Combustion Turbine is above 59°F. Gulf Power will be continuously notified of the status of each Combustion Turbine including output, and whether the Combustion Turbine is at baseload or in Power Augmentation mode. To allow for heating of steam lines and establishing stable and acceptable steam conditions, Gulf Power shall notify Shell no less than [**]times the number of Combustion Turbines to be placed in service in Power Augmentation mode prior to initiating Power Augmentation (the “Power Augmentation Lead Time”). Similarly, Gulf Power shall notify Shell no less than [**]before a Request for Energy results in Power Augmentation shutdown. The preceding two sentences shall not limit the provisions of the fourth paragraph of Section 1 of this Exhibit 5.2. Ramp rates for taking Power Augmentation in and out of service are specified in “Plant Response Characteristics” below. Once in service, Power Augmentation on a Combustion Turbine will be [**]. The Plant shall not be required to initiate Power Augmentation more than [**] for purposes of determining such number of times, any response (whether affirmative or negative or no response) to a notice by Shell to Gulf Power under the fourth paragraph of Section 1 of this Exhibit 5.2 shall be deemed to be a “time” if such notice by Shell was timely given as provided in the first sentence of such paragraph and such response by Gulf Power is given after the commencement of the applicable Power Augmentation Lead Time.

Plant Response Characteristics

Any variance in actual Plant response characteristics from Exhibit 5.2 may affect the determination of the Peak Availability Factor, the Off Peak Availability Factor and the Bonus Availability Factor but will not constitute a breach of this Agreement.

Once Generating Units have reached normal operating temperatures, the ramp rate (changes in output versus time) of the Plant will be no less than 7.5 MW per minute for each Combustion Turbine that is operating at part load. With all operating Combustion Turbines at base load, duct burners fired and Power Augmentation not in service, Plant output can be varied at a rate of no less than[**] MW per minute per Combustion Turbine by changing the level of duct firing and introducing the incremental steam produced into the Steam Turbine. The ramp rate associated with bringing Power Augmentation into service or taking Power Augmentation out of service will be no less than [**]MW per minute.

The load following capability of the Plant on AGC will be no less than [**] MW per minute for each Combustion Turbine that is operating at part load. With all Combustion Turbines operating at base load and duct burners fired, Plant output can be varied at a rate of no less than [**] MW per

Exhibit 5.2-3

minute per Combustion Turbine by changing the level of the duct firing, provided that (i) the Plant will not be required to operate on AGC if doing so would require the Plant to be operated outside of the Generation Unit Operating Principles, (ii) the Plant will not operate on AGC at any time during the transition into and out of duct firing associated with any Combustion Turbine(s) or at any time when any Combustion Turbine(s) are being started or stopped, and (iii) a Combustion Turbine will not operate on AGC at any time when such Combustion Turbine is operating in Power Augmentation mode.

The Plant will not be required to follow specified ramp rates during transition into and out of duct firing.

Exhibit 5.2-4

Annex 5.2 A

Tenaska Alabama Project

Request for Energy

ARTICLE 23Date: [ ] for Energy Deliveries on [ ]

	Delivered Energy
	Requested Energy not Subject to AGC or Plant Transition	Maximum Requested Energy Subject to AGC	Start/Stop Designation	No. of Combustion Turbines in Power Augmentation Mode
Hours Ending at Col. 1	(MW) Col. 2	(MW) Col. 3	Col. 4	Col. 5
0100
0200
0300
0400
0500
0600
0700
0800
0900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400

Total 0 0

Exhibit 5.2-5

Prepared by:

Name

Title

Exhibit 5.2-6

Explanatory Notes Re: Annex 5.2A

Notes by Column Number

(1) Hours are based upon a calendar Day using Central Prevailing Time.

(2) In the form of Annex 5.2A, this amount is to be estimated by Gulf Power no later than 2:00 p.m. of the preceding Business Day, with subsequent changes as permitted by Exhibit 5.2.

(3) Information within Annex 5.2A will provide the range of MW within which the Transmission Provider is entitled to vary the Request for Energy subject to AGC, with subsequent changes as permitted by Exhibit 5.2.

(4) To the extent all or a portion of the Plant is subject to a Start or Shutdown due to a Request for Energy, Annex 5.2A should provide an entry in this column for all applicable hours. For Generating Unit Starts insert 1. For Generating Unit Shutdowns insert 2.

Exhibit 5.2-7

Annex 5.2B Tenaska Alabama Project Confirmation Report of Delivered Energy Date: For Energy Deliveries on [ ]
	Energy Deliveries					Actual Fuel Usage			No. of Combustion Turbines in Power Augmentation Mode
	Energy not Subject to AGC or Plant Transition		Energy Subject to AGC		Energy Subject to Plant Transition	Natural Gas	Fuel Oil	Total Fuel
Hours Ending at Col. 1	Requested Energy (MW) Col. 2	Delivered Energy (MW) Col. 3	Requested Energy (MW) Col. 4	Delivered Energy (MW) Col. 5	Delivered Energy (MW) Col. 6	(MMBtu) Col. 7	(MMBtu) Col. 8	(MMBtu) Col. 9	Col. 10
0100
0200
0300
0400
0500
0600
0700
0800
0900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
Total	0	0	0	0	0	0	0	0

Prepared by: Acknowledged by:

Name               Name

Exhibit 5.2-8

Title              Title	Summary of Generating Unit Starts/Stops
		Combustion Turbines	Steam Turbines
	Starts during Operation
	Hot Starts
	Warm Starts
	Cold Starts
	Stops

Exhibit 5.2-9

Explanatory Notes Re Annex 5.2B

Notes by Column Number

(1) Hours are based upon a calendar Day using Central Prevailing Time.

(2) In the form of Annex 5.2A, this amount is to be estimated by Gulf Power no later than 2:00 p.m. of the preceding Business Day, with subsequent changes as permitted by Exhibit 5.2.

(3) To be provided by Shell within one Business Day after the Day of Energy deliveries covered by such Confirmation Report.

(4) Information within Annex 5.2A will provide the range of MW within which the Transmission Provider is entitled to vary the Request for Energy subject to AGC, with subsequent changes as permitted by Exhibit 5.2.

(5) See notes Re Column (3).

(6) To the extent all or a portion of the Plant is subject to a Start or Shutdown due to a Request for Energy, Annex 5.2A should provide a designation of these events in this column for all applicable hours. The Requests for Energy applicable to a Generating Unit undergoing a Start or Shutdown shall be equal to the Delivered Energy from such Generating Unit during the period of the Start or Shutdown, up to the maximum time therefore as set forth in Exhibit 8.4.

(7) See notes Re Column (3).

(8) See notes Re Column (3).

(9) See notes Re Column (3).

EXHIBIT 5.5

ESCALATION FACTOR

The Escalation Factor applicable to a Month shall be the Escalation Factor determined for the calendar year in which such Month occurs. The Escalation Factor for calendar year 2009 shall be one and the Escalation Factor applicable to calendar year 2010 and each subsequent calendar year shall be determined as follows:

Where:

Exhibit 5.2-10

EFy	=	Escalation Factor applicable to calendar year y.
EFy-1	=	Escalation Factor applicable to the calendar year immediately preceding calendar year y.
AEy	=	Annual Escalator applicable to calendar year y, determined as follows:

Where:
AEy	=	Annual Escalator applicable to calendar year y; provided that for any calendar year prior to 2016, if the Annual Escalator as so calculated is less than 1.02, it shall be deemed to be 1.02, and if the Annual Escalator as so calculated is greater than 1.03, it shall be deemed to be 1.03.
TGIy	=	TG Index as reported for the first Month of calendar year y.
TGIy-1	=	TG Index as reported for the first Month of the calendar year immediately preceding calendar year y.
MPIy	=	Metal Products Index as reported for the first Month of calendar year y.
MPIy-1	=	Metal Products Index as reported for the first Month of the calendar year immediately preceding calendar year y.

If any index set forth in the formula above is not available for the applicable Month at the time of calculation, the most recently available index shall be used on a provisional basis. When the index becomes available for the applicable Month, a retroactive recalculation shall be made, and the Parties shall adjust any payments made on the basis of the provisional index to reflect the recalculation using the actual index.

If any applicable index is published covering a period longer than one Month, for purposes of the calculation above, the reference to an index for a particular Month shall be deemed to be such longer period which includes such particular Month.

Exhibit 5.5-11

EXHIBIT 5.7

FINANCIAL SETTLEMENT PROCEDURE

In the event Shell elects the financial settlement procedures of Section 5.7, the indexed hours for daily strip price into the Southern Control Area as published in the daily Platts Energy Trader will be used to determine Alternate Liquidated Damages. The following tables will be used to distribute the daily strip price ($/MWh) into an hourly shape for peak and off-peak hours for the Months May through September:

Summer (May - September)
Strip Price Multipliers
Hour	Weekday Hourly Strip Energy Price	Weekend/Holiday Hourly Strip Energy Price
6:00 - 7:00 AM CPT	[**]	[**]
7:00 - 8:00 AM CPT	[**]	[**]
8:00 - 9:00 AM CPT	[**]	[**]
9:00 - 10:00 AM CPT	[**]	[**]
10:00 - 11:00 AM CPT	[**]	[**]
11:00 AM - Noon CPT	[**]	[**]
Noon - 1:00 PM CPT	[**]	[**]
1:00 - 2:00 PM CPT	[**]	[**]
2:00 - 3:00 PM CPT	[**]	[**]
3:00 - 4:00 PM CPT	[**]	[**]
4:00 - 5:00 PM CPT	[**]	[**]
5:00 - 6:00 PM CPT	[**]	[**]
6:00 - 7:00 PM CPT	[**]	[**]
7:00 - 8:00 PM CPT	[**]	[**]
8:00 - 9:00 PM CPT	[**]	[**]
9:00 - 10:00 PM CPT	[**]	[**]

Summer (May - September)
Strip Price Multipliers
Hour	Weekday Hourly Strip Energy Price	Weekend/Holiday Hourly Strip Energy Price
Midnight - 1:00 AM CPT	[**]	[**]
1:00 - 2:00 AM CPT	[**]	[**]
2:00 - 3:00 AM CPT	[**]	[**]
3:00 - 4:00 AM CPT	[**]	[**]
4:00 - 5:00 AM CPT	[**]	[**]
5:00 - 6:00 AM CPT	[**]	[**]
10:00 PM - 11:00 PM CPT	[**]	[**]
11:00 PM - Midnight CPT	[**]	[**]

Exhibit 5.5-12

The following tables will be used to distribute the daily strip price ($/MWh) into an hourly shape for hours for the Months December through February:

Winter (December - February)
Strip Price Multipliers
Hour	Weekday Hourly Strip Energy Price	Weekend/Holiday Hourly Strip Energy Price
6:00 - 7:00 AM CPT	[**]	[**]
7:00 - 8:00 AM CPT	[**]	[**]
8:00 - 9:00 AM CPT	[**]	[**]
9:00 - 10:00 AM CPT	[**]	[**]
10:00 - 11:00 AM CPT	[**]	[**]
11:00 AM - Noon CPT	[**]	[**]
Noon - 1:00 PM CPT	[**]	[**]
1:00 - 2:00 PM CPT	[**]	[**]
2:00 - 3:00 PM CPT	[**]	[**]
3:00 - 4:00 PM CPT	[**]	[**]
4:00 - 5:00 PM CPT	[**]	[**]
5:00 - 6:00 PM CPT	[**]	[**]
6:00 - 7:00 PM CPT	[**]	[**]
7:00 - 8:00 PM CPT	[**]	[**]
8:00 - 9:00 PM CPT	[**]	[**]
9:00 - 10:00 PM CPT	[**]	[**]

Winter (December - February)
Strip Price Multipliers
Hour	Weekday Hourly Strip Energy Price	Weekend/Holiday Hourly Strip Energy Price
Midnight - 1:00 AM CPT	[**]	[**]
1:00 - 2:00 AM CPT	[**]	[**]
2:00 - 3:00 AM CPT	[**]	[**]
3:00 - 4:00 AM CPT	[**]	[**]
4:00 - 5:00 AM CPT	[**]	[**]
5:00 - 6:00 AM CPT	[**]	[**]
10:00 PM - 11:00 PM CPT	[**]	[**]
11:00 PM - Midnight CPT	[**]	[**]

 

Exhibit 5.7 – Page 1 of 4

The following tables will be used to distribute the daily strip price ($/MWh) into an hourly shape for hours for the Spring and Fall months (March-April, October-November):

Spring/Fall (March-April, October-November)
Hour Strip Price Multipliers
Hour	Weekday Hourly Strip Energy Price	Weekend/Holiday Hourly Strip Energy Price
6:00 - 7:00 AM CPT	[**]	[**]
7:00 - 8:00 AM CPT	[**]	[**]
8:00 - 9:00 AM CPT	[**]	[**]
9:00 - 10:00 AM CPT	[**]	[**]
10:00 - 11:00 AM CPT	[**]	[**]
11:00 AM - Noon CPT	[**]	[**]
Noon - 1:00 PM CPT	[**]	[**]
1:00 - 2:00 PM CPT	[**]	[**]
2:00 - 3:00 PM CPT	[**]	[**]
3:00 - 4:00 PM CPT	[**]	[**]
4:00 - 5:00 PM CPT	[**]	[**]
5:00 - 6:00 PM CPT	[**]	[**]
6:00 - 7:00 PM CPT	[**]	[**]
7:00 - 8:00 PM CPT	[**]	[**]
8:00 - 9:00 PM CPT	[**]	[**]
9:00 - 10:00 PM CPT	[**]	[**]

Spring/Fall (March-April, October-November)
Hour Strip Price Multipliers
Hour	Weekday Hourly Strip Energy Price	Weekend/Holiday Hourly Strip Energy Price
Midnight - 1:00 AM CPT	[**]	[**]
1:00 - 2:00 AM CPT	[**]	[**]
2:00 - 3:00 AM CPT	[**]	[**]
3:00 - 4:00 AM CPT	[**]	[**]
4:00 - 5:00 AM CPT	[**]	[**]
5:00 - 6:00 AM CPT	[**]	[**]
10:00 PM - 11:00 PM CPT	[**]	[**]
11:00 PM - Midnight CPT	[**]	[**]

Gulf Power reserves the right to adjust annually the hourly multipliers for any Season following the fifth Annual Period or to change the provider of the daily strip price and/or the product used to calculate financial settlement; provided, however, that (i) the sum of the hourly multipliers shall always equal (16) for peak hours and eight (8) for off-peak hours, (ii) such multipliers shall be distributed across the hours in a commercially reasonable manner and (iii) such hourly distribution will not be based on the anticipated availability status of the Plant.

For each hour that the Plant is scheduled, the Alternate Liquidated Damages shall equal the hourly strip energy price corresponding to Gulf Power’s Schedules multiplied by the Schedule amount.

Example 1

If Shell elected financial settlement when the Plant was scheduled to operate on Natural Gas and 200 MW were unavailable between 1:00 and 2:00 PM on a weekday in July when the indexed peak daily strip price into the Southern Control Area as published in the daily Platts Energy Trader was $100/MWh, ED=[**]MWh, VER=$[**]/MWh, DGP=$[**]/MMBtu, RHR=[**]MMBtu/MWH, FHR=$[**]/FFH, the Alternate Liquidated Damages would be calculated as follows:

Alternate Liquidated Damages (ALD)=(indexed peak and/or off-peak daily strip price into the Southern Control Area as published in the daily Platts Energy Trader * applicable Hourly Strip Price Multiplier)-(FHR+ED_*VER+ RHR_*ED_*DGP) = ($100/MWh * [**]*[**]MW)-($ [**]/MWh+[**]MMBtu/MWh*[**] MWh*$10/MMBtu/MWh) = $[**]

Where:

ALD=Alternate Liquidated Damages determined pursuant to Exhibit 5.7.

ED=Energy Deficiency (scheduled energy – delivered energy) in MWh for each hour Seller has elected to pay ALD per Section 5.7.

VER=Variable Energy Rate expressed in $/MWH.

DGP=Delivered Gas Price for the applicable Gas Day (expressed in $/MMBtu).

RHR=Reference Heat Rate per Section 8.3 (a).

FHR=Based Fired Hour Rate as adjusted pursuant to Section 8.5 expressed in $/Factored Fired Hour.

FFH = Factored Fired Hour as determined per this Agreement.

Shell pays to Gulf Power the positive value of the sum of the ALD hourly values for the applicable continuous hours of requested energy schedule. If the sum of the ALD hourly values for the applicable continuous hours of the requested energy schedule is a negative value, then there is no payment made by Shell to Gulf Power for that period of Financial Settlement.

 

Exhibit 5.7 – Page 2 of 4

EXHIBIT 6.2

FUEL OIL SPECIFICATIONS

Liquid Fuel Specifications
Applicability	Property	Point of Applicability (a)	ASTM Test Method (c)	No.2 Fuel Oil Standard (b)
Combustion Turbine Requirements	Kin. Viscosity, cSt, 100°F (37.8°C), min Kin. Viscosity, cSt, 100°F (37.8°C), max (e) Kin. Viscosity, cSt, 210°F (98.9°C), max (e) Specific Gravity, 60°F (15.6°C), max Flash Point, °F (°C), min (g) Distillation Temp., 90% Point, °F (°C), max Pour Point, °F (°C), max	Delivery Delivery Delivery Delivery Delivery Delivery Delivery	D445 D445 D445 D1298 D93 D86 D97	.5(d) 5.8 -- Report Report 650 (338) .0 (-18) or 20 (7) below min. ambient
	Hydrogen, Wt. %, min (k) Carbon Residue, Wt. % (10% Bottoms) max Direct Pressure Atomization Carbon Residue, Wt. % (100% Sample) max Air Atomization, Low Pressure Carbon Residue, Wt. % (100% Sample) max Air Atomization, High Pressure	Delivery Delivery Delivery Delivery	(i) D524 D524 D524	Report .25 1.0 --
	Ash, ppm, max Trace Metal Contaminants, ppm, max (h) Sodium plus Potassium Lead Vanadium (untreated) Vanadium (treated 3/1 wt. Ratio Mg/V) Calcium Other Trace Metals above 5 ppm	Combustor Combustor	D482 (i)	50 1 1 .5 -- 2 Report
	Filterable Dirt, mg/100ml, max Water & Sediment, Vol. %, max. Water Content, Vol. %, max Thermal Stability, Tube No., max Fuel Compatibility, Tube No., max (50/50 mix with second fuel) Cetane No., min (Diesel Engine Start Only) Sulfur, Wt. %, max Wax Content, Wt. % Wax Melting Point, °F	Delivery Delivery Fuel Skid Delivery Delivery Delivery Delivery Delivery Delivery	D2276 D1796 D95 D1661 D1661 D975 D129 (i) (i)	4 .1 .1 -- -- 40 Report -- --

Exhibit 6.2-1

Liquid Fuel Specifications
The specifications below apply only when specific environmental codes exist.
Environ-mental Code Related Require- ments	Sulfur, Wt. %, max Nitrogen, Wt. %, max Hydrogen, Wt. %, min. Ash plus Vanadium, ppm, max.	Delivery Delivery Delivery Delivery	D129 (i) (i) (i)	Compliance to any applicable codes. Fuel-bound nitrogen may be limited to meet any applicable codes on total NOx emission. Minimum hydrogen level may be necessary to meet any applicable stack plume opacity limits (k). Ash plus vanadium content of ash-bearing fuels may be limited to meet applicable stack particulate emission codes (1).

Notes to Table 2

(a) The fuel properties specified refer to the fuel at different points in the overall system:

Delivery – Fuel as delivered to the turbine site

Fuel Skid –Fuel at inlet of fuel skid at turbine

Combustor – Fuel at turbine combustors

(b) No. 2 Fuel Oil.

(c) ASTM Book of Standards, Parts 23 and 24.

(d) In the viscosity range of 0.5 cSt to 1.8 cSt, special fuel pumping equipment may be required.

(e) The maximum allowable viscosity at the fuel nozzle is 20 cSt for high pressure air atomization and 10 cSt for low pressure air and direct pressure atomization. The fuel may have to be preheated to reach this viscosity, but in no instance shall it be heated above 275°F (135°C). (This maximum fuel temperature of 275°F is allowed only with residual fuels.) The viscosity of the fuel at initial light-off must be at or below 10 cSt.

(f) A specific gravity of 0.96 is based on average fuel desalting capability with standard washing systems. Fuels with specific gravities greater than 0.96 may be desalted to the required minimum sodium plus potassium limits by using higher capability desalting equipment (with higher attendant cost) or by increasing the gravity difference between the fuel and wash water by blending the fuel with a compatible distillate.

(g) The fuel must comply to all applicable codes for flash point.

(h) A total ash less than 3 ppm is acceptable in place of trace metal analysis.

(i) No standard reference tests exist; methods used should be mutually acceptable to General Electric and the user.

(j) Water content of crude oils should be reduced to the lowest level practical, consistent with

Exhibit 6.2-2

capability of available fuel treatment equipment, to minimize the chance of corrosion of fuel system components. In no case shall the water content exceed 1.0 vol. %.

(k) A minimum hydrogen content is set both to control flame radiation in the combustor and to limit smoke emissions, where the latter is required by local codes. The limits are 12.0% minimum for true distillates and 11.0% for Ash-bearing fuels (11.3% where the carbon residue exceeds 3.5%). In each case it is assumed that the proper combustor and fuel atomization system are used. Where the hydrogen content of the fuel is below these limits, General Electric should be consulted for appropriate action.

(l) Local codes on total stack particulate emissions may set an upper limit on the sum of the ash (nonfilterable) in the original fuel plus the vanadium content. The vanadium together with the required magnesium inhibitor may be a major contributor to total stack particulate emissions. In estimating these emissions for comparison with the code, all of the following sources may have to be considered; vanadium, additives, fuel ash and total sulfur in the fuel; noncombustible particulates in the inlet air; solids from any injected steam or water; and particles from incomplete fuel combustion. Where an estimate of stack particulate emissions is required, General Electric should be consulted.

Exhibit 6.2-3

EXHIBIT 7.1

LONG TERM MAINTENANCE SCHEDULE

1. Scheduled Maintenance Plan

1.1 Overview

The primary objective of Owner’s maintenance plan for the Plant will be to coordinate maintenance schedules with the power sales requirements of Gulf Power while optimizing maintenance cost and maximizing equipment availability. This maintenance plan has been developed utilizing vendor supplied maintenance and instruction manuals.

The scheduled maintenance plan and major component projected useful life and expected repair intervals are illustrated in the tables below.

1.2 Multi-Year Maintenance Agreement

Owner’s strategy on managing turbine-generator maintenance is to negotiate a multi-year maintenance agreement with the turbine equipment suppliers in parallel with the negotiations to purchase the turbine-generator equipment for the project. The maintenance agreement covers major component parts replacement, major component parts repair and provides for the labor and services for scheduled and unscheduled maintenance inspections. Owner has negotiated a long-germ maintenance agreement with the General Electric Company on their F technology combustion turbine-generators and associated steam turbine-generator equipment. This contract has been negotiated and signed with General Electric prior to the financial close of the project.

The maintenance agreement provides Owner with assurances as to the availability of covered parts at the prices and escalation rates set forth in the maintenance agreement and the timely provision of inspections and repair of covered parts. The maintenance agreement removes uncertainty from the project as to pricing and escalation and the equipment supplier assumes the risk of major component parts life.

1.3 Combustion Gas Turbines & Generators

1.3.1 Recommended Inspection Intervals:

Inspection Type	Inspection Intervals
Combustion/Hot-Gas-Path	Every [**] Hours
Major	Every [**] Hours

Exhibit 7.1 - 1

1.3.2 Estimated Maintenance Outage Schedules

Inspection Type	Duration
Combustion/Hot-Gas-Path	[**] Days (Two 12-Hour Shifts)
Major	[**] Days (Two 12-Hour Shifts)

1.3.3 Combustion Inspection

The combustion inspection is a relatively short disassembly shutdown inspection of fuel nozzles, liners, transition pieces, crossfire tubes and retainers, spark plug assemblies, flame detectors and combustor flow sleeves. This inspection concentrates on the combustion liners, transition pieces and fuel nozzles which are recognized as being the first to require replacement and repair in a good maintenance program.

The combustion liners, transition pieces and fuel nozzles will be removed and replaced with new or repaired components to minimize down time. The removed liners, transition pieces and fuel nozzles will then be cleaned and repaired after the unit is returned to operation and be available for the next inspection interval.

1.3.4 Hot-Gas-Path Inspection

The purpose of hot-gas-path inspection is to examine those parts exposed to high temperatures from the hot gasses discharged from the combustion process. The hot-gas-path inspection includes the full scope of the combustion inspection and, in addition, a detailed inspection of the turbine vanes and turbine blades. To perform this inspection, the top half of the turbine shell must be removed.

The hot-gas-path inspection interval will be determined by the visual borescope evaluation made at the time of the combustion inspection. Any parts needing repair will be replaced with parts present at the job site prior to turbine shell removal. Repairs will be accomplished on the removed parts at a later time. This allows for maximum availability (minimum downtime) of the unit and allows maximum utilization of personnel.

1.3.5 Major Inspection

The purpose of the major inspection is to examine all of the internal rotating and stationary components from the inlet of the machine through the exhaust section of the machine. All of the major flange-to-flange components of the gas turbine which are subject to wear during normal turbine operation will be inspected. This inspection includes elements of the combustion and hot-gas-path inspection, in addition to laying open the complete flange-to-flange turbine to the horizontal joints to inspect individual items. The alignment of the gas turbine to the generator and the gas turbine to accessory gear will be checked during the major inspection.

1.4 Steam Turbine & Generator

Exhibit 7.1 - 2

The maintenance plan for the steam generator will consist of a continuous monitoring program and an instrumented vibration data collection system.

1.4.1 Running Inspections

The planned maintenance will be based on a quarterly lubrication oil sampling and analysis program, coupled with the continuous monitoring program to record and trend such parameters as temperatures, pressures, vibration levels and trends, rotor position indication, generator cooler performance, stability of operations and the trend of operational performance among others to determine the satisfactory operation of the machine.

1.4.2 Bi-Annual Inspections

A bi-annual inspection will be conducted to verify the proper lubrication, cleaning, cooling and clearance maintenance of the bearing lubrication oil system. Thrust bearing clearances will be verified. The lubrication system operational control, indications and alarms will be verified. Valve operating gear, servo-motors and instrumentation inspections will be conducted. Control components will be checked for correct response, stability and accuracy. All vendor recommended test and inspections will be conducted at the time of shut down as well as any requirements by the insurance carrier.

1.4.3 Turbine Major Inspection

The turbine casing will be lifted and a complete internal inspection will be conducted following the sixth year of operation unless operational conditions require an earlier investigation. During this inspection all parts such as casing, rotor assemblies, bearings, diaphragms, packing glands, control valves and components will be cleaned and inspected. Worn or defective parts will be repaired or replaced. Clearances between rotating and stationary elements as well as alignment of the unit will be checked and adjusted as needed.

1.5 Heat Recovery Steam Generator

In addition to the continuous monitoring of operating conditions of the boilers, an annual shut down inspection will be conducted to coincide with the turbine inspections consisting of the following:

Shut down, cool down, vent and fill the HRSGs. Inspect all interior surfaces of the HRSGs for warped tube bundles, eroded or damaged fins and tubes, damaged or missing liner plates and clips, guide vanes or deflectors and all insulation. Examine all internal surfaces of the drums for corrosion, erosion, cracks, scale and dirt. Check the integrity of the internal steam separating devices, feedwater, blow down and chemical feed piping. Determine the need for cleaning and proper method if needed as well as the effectiveness of the boiler water chemistry program. Service safety

Exhibit 7.1 - 3

valves and verify their proper functioning. Check all flow elements and orifices for proper condition. Check all valves for proper operation by cycling manual valves and inspecting for evidence of leakage. Repair all documented leaking valves and isolation devices. Inspect all surfaces in the exhaust gas path for corrosion and damage. Check all heat tracing elements for proper operation.

2. Maintenance Program

The maintenance program is administered under the direction of the Plant’s maintenance manager. The Plant’s maintenance manager ensures that the Plant maintenance personnel follow maintenance schedules and procedures outlined in the Plant’s maintenance plan.

Key elements of the maintenance program for the plants include the following:

2.1 Outage Planning – conduct effective outage planning that is designed to minimize outage time and maximize Plant availability and coordinate with and support Gulf Power’s power sales requirements.

2.2 Preventative Maintenance – The maintenance program emphasizes preventive maintenance as its first line of defense to support the reliable long-term operation of the Plant. All maintenance personnel are trained in, and will be required to follow, the maintenance program which is based upon the manufacturer’s recommended preventive maintenance schedules/procedures for each equipment item. Preventive maintenance schedules are entered into the Computerized Maintenance Management Information Software (CMMS) package discussed below. This computer-based system allows the accurate tracking of all necessary preventive maintenance for the Plant’s components.

2.3 Corrective Maintenance – Minor equipment breakdowns are handled by the maintenance crew. Major equipment repairs may be sub-contracted to outside vendors for repair action.

2.4 Predictive Maintenance – A predictive maintenance program is implemented which can include one or all of the following:

• Vibration Analysis – Regular checking of equipment vibration signatures to detect imbalances or bearing faults.

• Lube Oil Analysis – Testing of lubrication oils and greases to detect water, acids or other dissolved contaminants. These analyses also evaluate wear particles to determine type and severity of machinery wear.

• Dielectric Oil Analysis – Testing of transformer oils for dielectric strength and for dissolved gases and water.

• Infrared Thermography (IRT) – Infrared imaging of operating electrical or

Exhibit 7.1 - 4

mechanical equipment to detect hot spots.

2.5 Maintenance Management Information System – A maintenance management information system is essential to properly support plant O&M activities. As mentioned previously, a Computerized Maintenance Management Software (CMMS) package is utilized at the Plant. This program ties together the purchasing, inventory control and maintenance scheduling and documentation aspects of plant management. The CMMS program also helps to reduce costs and increase Plant availability by providing trending information on inventory use, component failures and equipment operating histories.

Exhibit 7.1 - 5

Scheduled Maintenance Plan

Scheduled Maintenance Item Combustion Turbine-Generator	2004	2005	2006	2007	2008	2009
Hot-Gas-Path Inspection/Repair			X			X
Major Inspection/Repair						X
Generator/Electrical/Inspection	X	X	X	X	X
Generator Major Inspection						X
Inlet Filtration		X		X		X
Steam Turbine
Bi-Annual Inspection/Repair		X		X		X
Major Inspection/Repair						X
Generator/Electrical Inspection		X		X		X
Generator Major Inspection						X
Heat Recovery Steam Generator #1
Annual Inspection Repair	X	X	X	X	X	X
Chemical Cleaning/Repair						X
Condenser
Annual Inspection/Repair	X	X	X	X	X	X
Feedwater Pumps
Overhaul						X
Balance of Plant
Mechanical	X	X	X	X	X	X
Electrical	X	X	X	X	X	X
Power Distribution	X	X	X	X	X	X
Other	X	X	X	X	X	X
Cooling Tower
Clean & Inspect	X		X		X
Overhaul						X

Exhibit 7.1 - 6

FLOW PATH COMPONENT PROJECTED USEFUL LIFE

AND EXPECTED REPAIR INTERVALS

The projected useful life on the components listed below is based on the unit firing on Gas fuel at base load operation with greater than 100 hours per start.

Combustor Section	Repair Hours	Replace Hours
-Fuel nozzles	[**]	[**]
-Crossfire tubes	[**]	[**]
-Transition pieces	[**]	[**]
-Caps	[**]	[**]
-Combustion liners	[**]	[**]
Turbine Section
-Stage 1 nozzles	[**]	[**]
-Stage 2 nozzles	[**]	[**]
-Stage 3 nozzles	[**]	[**]
-Stage 1 shrouds	[**]	[**]
-Stage 2 shrouds	[**]	[**]
-Stage 3 shrouds	[**]	[**]
-Stage 1 bucket	[**]	[**]
-Stage 2 bucket	[**]	[**]
-Stage 3 bucket	[**]	[**]
Compressor Section
-Compressor blades	[**]

EXHIBIT 7.3

GENERATING UNIT OPERATING PRINCIPLES

Exhibit 7.1 - 7

This Exhibit 7.3 provides operating guidelines for the Parties with respect to how it is expected that the Plant will be operated in conjunction with Requests for Energy by Gulf Power. The Parties acknowledge that this Exhibit represents Owner’s current judgment on the expected basis upon which the Generating Units will be operated in conjunction with a Request for Energy by Gulf Power. Numbers provided or calculated in this Exhibit represent estimated average equipment performance for the first year of operation based upon a Contract Capacity of 885 MW when firing on Gas. From time to time, Shell shall propose to Gulf Power certain amendments to the Generating Unit Operating Principles based upon the history of the Plant operations in response to Requests for Energy, requirements of Owner, manufacturer’s recommendations, Prudent Generator Practices, the expected degradation in Plant capacity or performance and the expected restoration of Plant capacity or performance due to maintenance activity. The Parties shall, in good faith, negotiate a mutually agreeable amendment to the Generating Unit Operating Principles in consideration of the amendments; provided; however, that any amendments required by Owner shall be incorporated into this Exhibit 7.3. In implementing these Generating Unit Operating Principles, it is the understanding of the Parties that the sum of all maximum Generating Unit outputs less auxiliaries estimated by this Exhibit 7.3 at summer design conditions (99°F dry bulb and 76°F wet bulb) shall be equal to or greater than the Contract Capacity.

This Exhibit 7.3 will be utilized for the purposes of determining Starts of Generating Units pursuant to Sections 8.4 and 8.5. For the avoidance of doubt, the Generating Unit Operating Principles as set forth in this Exhibit 7.3 are used in the Energy Conversion Agreement to determine whether a manner of dispatch requested by Gulf Power (either expressly or through AGC) is in accordance with Section 7.3 of the Energy Conversion Agreement or is a Non-Conforming Request for Energy and to determine the extent to which a start of a Generating Unit will constitute a Gulf Power Factored CT Start or a Steam Turbine Start for purposes of Sections 8.4 and 8.5 and Exhibit 8.4. The Generating Unit and Plant performance contained in this Exhibit 7.3 are estimates only and actual performance of the Plant may vary from the Generating Unit Operating Principles. Any such variance may affect the determination of the Peak Availability Factor, the Off Peak Availability Factor and the Bonus Availability Factor, may affect the extent to which the start of a Generating Unit will constitute a Gulf Power Factored CT Start or a Steam Turbine Start for purposes of Sections 8.4 and 8.5 and Exhibit 8.4, and may affect the amount of payments to be made by Shell under Section 5.6, but will not constitute a breach of the Energy Conversion Agreement.

1. The number of Combustion Turbines operating is determined by the requested total Plant output and the average compressor inlet temperature of the operating units. For the purposes of determining Starts of Generating Units, it is to be assumed that Combustion Turbine(s) and the Steam Turbine may operate from minimum available unit output (as set forth below) to the maximum available unit output (as set forth below) based on the number of Generating Units in service less auxiliary power (as set forth below). When increasing load, the optimum heat rate transition from two Combustion Turbines to three Combustion Turbines occurs when the two Combustion Turbines are at base load plus approximately [**] MW of duct firing. When decreasing load, the optimum heat rate transition from three Combustion Turbines to two Combustion Turbines occurs at approximately 74% load on the three Combustion Turbines.

2. Maximum Combustion Turbine Generator Unit Output without Power Augmentation (also

Exhibit 7.3-8

known as “base load” or “100% load”) is calculated as follows:

	GT Max	=	c/(a + bt2 ln t)
Where:	GT Max	=	Maximum Combustion Turbine Generator Unit Output without Power Augmentation in KW
			(Maximum expected variance is +2% - 6%)
	a	=	[**]x 10-6
	b	=	[**]x 10-11
	c	=	[**] (representing a margin for expected first year degradation)
	t	=	Combustion Turbine compressor inlet temperature (CIT) in °F

Maximum Combustion Turbine Generator Unit Output with Power Augmentation (referred to as “Base Load with Power Augmentation” or “Maximum Load with Power Augmentation”) is the sum of GT Max above and Power Augmentation (PA) where PA is calculated as follows:

	PA	=	d(e + f/t)½
Where:	PA	=	Power Augmentation from one Combustion Turbine Generating Unit in kW.
	d	=	[**]
	e	=	[**]x 108
	f	=	[**]x 1011

3. When operating, each Combustion Turbine must be loaded between about [**]% and 100% of its Maximum Combustion Turbine Generator Unit Output.

4. [**]% load.

5. Auxiliary power without duct firing is estimated to be about [**] MW for 1-unit operation, [**] MW for 2-unit operation and [**] MW for 3-unit operation. When duct firing, auxiliaries shall be increased by approximately [**]% of the duct-fired output. The maximum expected variance is + 4MW.

6. The Minimum Output for the Steam Turbine is calculated as follows:

Exhibit 7.3-9

STG_min = [[**] (H₁ + H₂ + H₃) – [**]] [1 + .03 (83 – t)/63]c

H_g = 1/(a – b x L_g/lnL_g)

Where:
	STGmin	=	Minimum Output for the Steam Turbine (the predicted Steam Turbine output with no duct firing) in kW (maximum expected variance is + 15 MW).
	g	=	denotes Combustion Turbine No. 1, 2 or 3
	Hg	=	useful available heat from Combustion Turbine No. 1, 2 or 3
	Lg	=	load on Combustion Turbine No. 1, 2 or 3 as a percent of base load (i.e., % of Maximum Combustion Turbine Generator Unit Output, [**]to 100%), %
	t	=	Combustion Turbine compressor inlet temperature (CIT) in °F
	a	=	[**]
	b	=	[**]
	c	=	[**] (representing a margin for expected first year degradation)

7. Without Power Augmentation and with duct firing, the predicted Maximum Steam Turbine Generator Output (MSTOx) is [**] kW with one Combustion Turbine operating, [**] kW with two Combustion Turbines operating and [**] kW with three Combustion Turbines operating. The maximum expected variance is +15 MW. With Power Augmentation and duct firing the Maximum Steam Turbine Output with three Combustion Turbines operating (STGmax3PA) is determined as follows:

	STGmax3PA	=	MSTO3 + STGmax3PA Adjustment
And
	STGmax3PA Adjustment	=	a ( b + c t2 )
Where:
	MSTO3	=	Maximum Steam Turbine Output for three Combustion Turbines operating without Power Augmentation, with duct firing, in kW.

Exhibit 7.3-10

STGmax3PA Adjustment		Maximum Steam Turbine Output with three Combustion Turbines operating with duct firing and at least one operating with Power Augmentation (STGmax3PA) minus the Maximum Steam Turbine Output with three Combustion Turbines operating with duct firing and without Power Augmentation, in kW.
a	=	[**]
c	=	[**]
t	=	Combustion Turbine compressor inlet temperature (CIT), °F
subscript or x	=	denotes the number of Combustion Turbines operating

Note that total net Plant maximum incremental output from Power Augmentation is equal to three times PA (from 2 above) plus STGmax3PA Adjustment (above expression).

8. The above formulas assume that all units are in service and capable of operating at design levels. If any units trip or must be taken out of service or operated at less than design load, Shell will notify Gulf Power but the Plant will be allowed to operate with the then-available equipment in a manner to most closely meet the Request for Energy.

9. All load points specified in this Exhibit 7.3 as percentages shall be determined according to Prudent Generator Practices.

1.

Exhibit 7.3-11

EXHIBIT 8.3

CALCULATION OF REFERENCE HEAT RATES

This Exhibit provides the procedure for calculating the Reference Heat Rate (“RHR”) referred to in Section 8.3 of the Agreement applicable to each Heat Rate Test Date. In accordance with Section 8.3 of the Agreement, the Reference Heat Rate is used in conjunction with the Tested Heat Rate to establish the extent to which Heat Rate Payments are to be made by either Party. The Reference Heat Rate for each Heat Rate Test Date is calculated as follows:

Where:
	RHRx	=	Reference Heat Rate for Heat Rate Test Date x (expressed in MMBtu/MWh).
	Target HR	=	[**] MMBtu/MWh.
	HRDegrad(AFFHx)	=	Heat Rate Degradation determined from the attached Table 8.3 (depicted graphically in the attached Figure 8.3) as a function of Average Factored Fired Hours as of Heat Rate Test Date x, in percent (and expressed in the above formula as a fraction). After the First Contract Year the Average Factored Fired Hours shall equal the Average Factored Fired Hours as of the Heat Rate Test Date x plus the Average Factored Fired Hours determined in the Pre-Term Period.
	AFFHx	=	The sum of the Factored Fired Hours as of Heat Rate Test Date x for all three Combustion Turbines divided by three.

[**]

EXHIBIT 8.4

START CHARGES AND MAXIMUM TIMES FOR STARTS AND SHUTDOWNS

Start Charges

Calculation of Gulf Power Factored CT Starts

“Gulf Power Factored CT Starts” means for a Contract Year the sum of (a) the number of Shell Factored CT Commencements in such Contract Year, not to exceed the Maximum Reimbursable Shell CT Commencements for such Contract Year, plus (b) one-half of the number of Starts (including Starts following a System Trip, but excluding Starts following a Shell Trip) at Part Load, plus (c) the number of Starts (including Starts following a System Trip, but excluding Starts following a Shell Trip) at Normal Load, plus (d) in the case of the next Start following each System Trip, the applicable Trip Adder as determined below.

“Part Load” means the Combustion Turbine is not operated at greater than 60% load following the applicable Start and before its next Shutdown. “Normal Load” means the Combustion Turbine is operated at greater than 60% load following the applicable Start and before its next Shutdown.

“Shell CT Commencement” means the commencement of firing and operation of a Combustion Turbine (“CT Commencement”) at Owners request other than a Start.

“Shell Factored CT Commencements” shall equal (i) for the First Contract Year, the product of (a) the sum of (i) one-half of the number of Shell CT Commencements at Part Load, plus (ii) the number of Shell CT Commencements at Normal Load, plus (iii) the applicable Trip Adder for each Shell Trip, plus (iv) the total number of the Owner’s Combustion Turbine Starts (including the associated trip adders) that occur during the Pre-Term Period multiplied by (b) a fraction, the numerator of which is the number of Months in the First Contract Year and the denominator of which is 12, with the result of this calculation rounded to the nearest tenth; and, (ii) for each subsequent Contract Year (a) one-half of the number of Shell CT Commencements at Part Load, (b) plus the number of Shell CT Commencements at Normal Load, (c) plus the applicable Trip Adder for each Shell Trip.

“Maximum Reimbursable Shell CT Commencements” means (i) for the First Contract Year [**] minus the total number of the Owner’s Combustion Turbine Starts (including the associated trip adders) that occur during the Pre-Term Period; and, (ii) for each subsequent Contract Year, [**] plus the lesser of (a) [**] minus the number of Shell Factored CT Commencements in the immediately preceding Contract Year (but not less than zero) and (b) [**]. The numbers in this paragraph are based on Contract Years that are full calendar years. In the case of any Contract Year that is not a full calendar year, such numbers shall be adjusted by multiplying them by a fraction, the numerator of which is the number of Days in such Contract Year and the denominator of which is 365, with the result of this calculation rounded to the nearest whole number.

“System Trip” shall mean a trip of a Combustion Turbine caused by (a) abnormal conditions

Exhibit 8.4- 1

on the system of the Transmission Provider or (b) a direction from or other action by the Transmission Provider or independent system operator that did not result from any wrongful action or inaction by Shell or any failure of the Plant to operate in accordance with this Agreement or with the Energy Interconnection Agreement or (c) the failure of Gulf Power to supply Fuel meeting the specifications required by this Agreement.

“Shell Trip” shall mean any trip of a Combustion Turbine that is not a System Trip.

“Trip Adder” is determined as follows: A System Trip or a Shell Trip while a Combustion Turbine is operating at up to zero load shall count as two Gulf Power Factored CT Starts or Shell Factored CT Commencements, as applicable; a System Trip or a Shell Trip while a Combustion Turbine is operating at 80% or higher load shall count as 8 Gulf Power Factored CT Starts or Shell Factored CT Commencements, as applicable; and a System Trip or a Shell Trip while a Combustion Turbine is operating at between 0% and 80% load shall be counted as being equal 2 + (6 x Load% ÷ 80%) Gulf Power Factored CT Starts or Shell Factored CT Commencements, as applicable.

Maximum Number of Gulf Power Factored CT Starts

For each Contract Year, Gulf Power may not request more than [**] Gulf Power Factored CT Starts; provided that for the First Contract Year, Gulf Power may not request more than [**] Gulf Power Factored CT Starts less the total number of Combustion Turbine Starts (including associated trip adders) accumulated during the Pre-Term Period.

Maximum Start and Shutdown Times

The maximum times for Starts shall be as shown in the attached charts. The maximum time for shutdown of a Combustion Turbine from Minimum Load shall be based upon the expected ramp rate of [**] MW per minute.

Exhibit 8.4- 2

Generating Unit Startup Operating Guidelines

Requests for Energy during GT Startup

(Plant is operating before Start Request)

			Hour 1	Hour 2
Existing Plant Configuration	Units to be Started	Startup Duration	Energy Request Range (MWh)	Energy Request Range (MWh)
1 GT + ST	1 GT	[**]	[**]	[**]
2 GT + ST	1 GT	[**]	[**]	[**]
1 GT + ST	2 GT	[**]	[**]	[**]

Request for Energy During Hot Plant Startup

(Plant operating within the previous 8 hours before Start time requested)

		Hour 1	Hour 2
Desired Plant Configuration	Startup Duration	Energy Request Range (MWh)	Energy Request Range (MWh)
1 GT + ST	[**]	[**]	[**]
2 GT + ST	[**]	[**]	[**]
3 GT + ST	[**]	[**]	[**]

Request for Energy during Warm Plant Startup

(Plant operating during previous 8 through 48 hours before Start time requested)

		Hour 1	Hour 2	Hour 3
Desired Plant Configuration	Startup Duration	Energy Request Range (MWh)	Energy Request Range (MWh)	Energy Request Range (MWh)
1 GT + ST	[**]	[**]	[**]	[**]
2 GT + ST	[**]	[**]	[**]	[**]
3 GT + ST	[**]	[**]	[**]	[**]

Request for Energy during Cold Plant Startup

(Plant not operating within the 48 hours before Start time requested)

		Hours 1 - 2	Hour 3	Hour 4
Existing Plant Configuration	Startup Duration	Energy Request Range (MWh)	Energy Request Range (MWh)	Energy Request Range (MWh)
1 GT + ST	[**]	[**]	[**]	[**]
2 GT + ST	[**]	[**]	[**]	[**]
3 GT + ST	[**]	[**]	[**]	[**]

Note: Owner shall have the right to take any Generating Unit off turning gear if (a) [**]

Exhibit 8.4- 3

hours have elapsed following a Shutdown of that Generating Unit and (b) there has not been a Start of such Generating Unit since such Shutdown. If any Generating Unit is off turning gear as provided above, Shell shall have an additional [**] hours beyond the applicable Startup duration set forth in the foregoing charts to cause Owner to complete the Start of such Generating Unit.

EXHIBIT 8.6

BONUS AVAILABILITY FACTOR AND

AVAILABILITY BONUS PAYMENTS

1. Bonus Availability Factor

The Bonus Availability Factor for any Contract Year1 shall be calculated as follows:

Where:
BAFy	=	Bonus Availability Factor for Contract Year y, which shall be rounded to the nearest hundredth of a percent.
g	=	Each Bonus Hour during Contract Year y in which there was Requested Energy.
w	=	Total number of Bonus Hours during Contract Year y in which there was Requested Energy.

_________________________

¹ For the First Contract Year, Shell shall provide Gulf Power with the information necessary for Gulf Power to include Shell’s activities associated with the Plant during the Pre-Term Period. The calculation for the Bonus Availability Factor for the First Contract Year shall be calculated as if the First Contract Year had begun on June 1, 2009 and include all factors associated with Shell’s activities with the Plant during the Pre-Term Period.

Exhibit 8.4- 4

BDEg	=	(i) For the First Contract Year, the sum of the Base Delivered Energy during hour g (expressed in MWh) during the Pre-Term Period plus the Base Delivered Energy during hour g (expressed in MWh) during the First Contract Year, provided that if Base Delivered Energy for hour g plus the Availability Tolerance for hour g equals or exceeds Base Requested Energy for hour g, BDEg shall be deemed to be equal to BREg; and (ii) for each subsequent Contract Year, Base Delivered Energy during hour g (expressed in MWh), provided that if Base Delivered Energy for hour g plus the Availability Tolerance for hour g equals or exceeds Base Requested Energy for hour g, BDEg shall be deemed to be equal to BREg.
BREg	=	(i) For the First Contract Year, the sum of Base Requested Energy during hour g (expressed in MWh) during the Pre-Term Period plus the Base Requested Energy during hour g (expressed in MWh) during the First Contract Year; and (ii) for each subsequent Contract Year, Base Requested Energy during hour g (expressed in MWh).

2. Availability Bonus Payments

For any Contract Year in which the Bonus Availability Factor exceeds the Bonus Availability Target, the Availability Bonus Payment for such Contract Year shall be calculated as follows:

Where:
ABPy	=	Availability Bonus Payment for Contract Year y (expressed in Dollars).
BAFy	=	Bonus Availability Factor for Contract Year y.
BATy	=	Bonus Availability Target for Contract Year y.
f	=	Each Bonus Hour during Contract Year y in which there was Requested Energy.
t	=	Total number of Bonus Hours during Contract Year y in which there was Requested Energy.
BREf	=	Base Requested Energy for hour f (expressed in MWh).

Exhibit 8.6-5

ASBf = Allocated spread for hour f for purposes of determining the Availability Bonus Payment, which shall be the sum of (a) 100% of the portion of the Spark Spread for hour f up to $[**]/MWh, plus (b) 80% of the portion of the Spark Spread for hour f over $[**]/MWh and up to $[**]/MWh, plus (c) 50% of the portion of the Spark Spread for hour f over $[**]/MWh and up to $[**]/MWh, plus (d) 20% of the portion of the Spark Spread for hour f over $[**]/MWh and up to $[**]/MWh, plus (e) 0% of the portion of the Spark Spread for hour f over $[**]/MWh. The Spark Spread shall be calculated as provided in Section 2 of Exhibit 8.7.

EXHIBIT 8.7

PEAK AVAILABILITY FACTOR AND

PEAK AVAILABILITY PAYMENTS

1. Peak Availability Factor

For each Contract Year, the Peak Availability Factor for any Peak Availability Measurement Period shall be calculated as follows:

Where:
PAFm	=	Peak Availability Factor for Peak Availability Measurement Period m, which shall be rounded to the nearest hundredth of a percent.
i	=	(i) For the First Contract Year, each hour during Peak Availability Measurement Period for the 12-Month period inclusive of the Pre-Term Period and the First Contract Year in which there was an energy request (for Shell’s account) during the Pre-Term Period and Requested Energy during the First Contract Year, but excluding any hours for which both (a) the Spark Spread is less than or equal to zero and (b) Gulf Power would not have issued a Request for Energy but for the fact that the Plant was not capable of meeting the Request for Energy; and (ii) for each subsequent Contract Year, each hour during Peak Availability Measurement Period m in which there was Requested Energy, but excluding any hours for which both (a) the Spark Spread is less than or equal to zero and (b) Gulf Power would not have issued a Request for Energy but for the fact that the Plant was not capable of meeting the Request for Energy.

Exhibit 8.6-6

x	=	(i) For the First Contract Year, the total number of hours during Peak Availability Measurement Period for the 12-Month period inclusive of the Pre-Term Period and the First Contract Year in which there was an energy request (for Shell’s account) during the Pre-Term Period and Requested Energy during the First Contract Year, but excluding any hours for which both (a) the Spark Spread is less than or equal to zero and (b) Gulf Power would not have issued a Request for Energy but for the fact that the Plant was not capable of meeting the Request for Energy; and (ii) for each subsequent Contract Year, the total number of hours during Peak Availability Measurement Period m in which there was Requested Energy, but excluding any hours for which both (a) the Spark Spread is less than or equal to zero and (b) Gulf Power would not have issued a Request for Energy but for the fact that the Plant was not capable of meeting the Request for Energy.
BDEi	=	(i) For the First Contract Year, the sum of Base Delivered Energy (for Shell’s account) during the Pre-Term Period during hour i plus Base Delivered Energy during the First Contract Year, during hour i (expressed in MWh), provided that if such Base Delivered Energy for hour i plus the Availability Tolerance for hour i equals or exceeds Base Requested Energy for hour i, BDEi shall be deemed to be equal to BREi; and (ii) for each subsequent Contract Year, Base Delivered Energy during hour i (expressed in MWh), provided that if Base Delivered Energy for hour i plus the Availability Tolerance for hour i equals or exceeds Base Requested Energy for hour i, BDEi shall be deemed to be equal to BREi.
BREi	=	(i) For the First Contract Year, the sum of Base Requested Energy (for Shell’s account) during the Pre-Term Period for hour i plus Base Requested Energy during the First Contract Year, during hour i (expressed in MWh); and (ii) for each subsequent Contract Year, Base Requested Energy during hour i (expressed in MWh).

If the denominator of the fraction in the formula set forth above for any Peak Availability Measurement Period is less than the product of (a) 2500 hours multiplied by (b) the weighted average Contract Capacity during such Peak Availability Measurement Period (such product, the “Peak Request Shortfall”), the denominator of such fraction for such Peak Availability Measurement Period shall be increased by an amount equal to the Peak Request Shortfall for such Peak Availability Measurement Period and the numerator of such fraction shall be increased by an amount equal to the Peak Request Shortfall multiplied by the Peak Availability Target for such Peak Availability Measurement Period.

2. Peak Availability Payments

For any Peak Availability Measurement Period in which the Peak Availability Factor is less than the Peak Availability Target, the Peak Availability Payment for such Peak Availability Measurement Period shall be calculated as follows:

Exhibit 8.7-7

Where:
PAPm	=	Peak Availability Payment for Peak Availability Measurement Period m (expressed in Dollars), but in no event less than zero.
PATm	=	Peak Availability Target for Peak Availability Measurement Period m.
PAFm	=	Peak Availability Factor for Peak Availability Measurement Period m.
h	=	Each hour during Peak Availability Measurement Period m in which Base Requested Energy exceeded Base Delivered Energy.
k	=	Total number of hours during Peak Availability Measurement Period m in which Base Requested Energy exceeded Base Delivered Energy.
BREh	=	Base Requested Energy for hour h (expressed in MWh).
BDEh	=	Base Delivered Energy for hour h (expressed in MWh), provided that if Base Delivered Energy for hour h plus the Availability Tolerance for hour h equals or exceeds Base Requested Energy for hour h, BDEh shall be deemed to be equal to BREh.
ASh	=	Allocated spread for hour h for purposes of determining the Peak Availability Payment, which shall be the sum of (a) 100% of the portion of the Spark Spread for hour h up to $[**]/MWh, plus (b) 80% of the portion of the Spark Spread for hour h over $[**]/MWh and up to $[**]/MWh, plus (c) 50% of the portion of the Spark Spread for hour h over $[**]/MWh and up to $[**]/MWh, plus (d) 20% of the portion of the Spark Spread for hour h over $[**]/MWh and up to $[**]/MWh, plus (e) 0% of the portion of the Spark Spread for hour h over $[**]/MWh.

The “Spark Spread” for any hour shall be the amount calculated as follows:

Where:
SS	=	Spark Spread for the applicable hour (expressed in $/MWh).

Exhibit 8.7-8

EI	=	The Electric Index applicable to such hour(expressed in $/MWh); provided that if EI is less than the sum of VM and FS, EI shall be deemed to be equal to the sum of VM and FS.
VM	=	The Variable Maintenance Rate for the Month in which such hour occurs (expressed in $/MWh).
FS	=	Fuel Savings for such hour (expressed in $/MWh).

EXHIBIT 8.8

OFF PEAK AVAILABILITY FACTOR AND

OFF PEAK AVAILABILITY PAYMENTS

1. Off Peak Availability Factor

For each Contract Year, the Off Peak Availability Factor for any Off Peak Availability Measurement Period shall be calculated as follows:

Where:
OPAFm	=	Off Peak Availability Factor for Off Peak Availability Measurement Period m, which shall be rounded to the nearest hundredth of a percent.

Exhibit 8.7-9

j	=	(i) For the First Contract Year, each hour during Off Peak Availability Measurement Period for the 12-Month period inclusive of the Pre-Term Period and the First Contract Year in which there was an energy request (for Shell’s account) during the Pre-Term Period and Requested Energy during the First Contract Year, but excluding any hours for which both (a) the Spark Spread is less than or equal to zero and (b) Gulf Power would not have issued a Request for Energy but for the fact that the Plant was not capable of meeting the Request for Energy; and (ii) for each subsequent Contract Year, each hour during Off Peak Availability Measurement Period m in which there was Requested Energy, but excluding any hours for which (a) the Spark Spread is less than or equal to zero and (b) Gulf Power would not have issued a Request for Energy but for the fact that the Plant was not capable of meeting the Request for Energy.
t	=	(i) For the First Contract Year, the total number of hours during Off Peak Availability Measurement Period for the 12-Month period inclusive of the Pre-Term Period and the First Contract Year in which there was an energy request (for Shell’s account) during the Pre-Term Period and Requested Energy during the First Contract Year, but excluding any hours for which both (a) the Spark Spread is less than or equal to zero and (b) Gulf Power would not have issued a Request for Energy but for the fact that the Plant was not capable of meeting the Request for Energy; and (ii) for each subsequent Contract Year, the total number of hours during Off Peak Availability Measurement Period m in which there was Requested Energy, but excluding any hours for which both (a) the Spark Spread is less than or equal to zero and (b) Gulf Power would not have issued a Request for Energy but for the fact that the Plant was not capable of meeting the Request for Energy.
BDEj	=	(i) For the First Contract Year, the sum of Base Delivered Energy (for Shell’s account) during the Pre-Term Period during hour j plus Base Delivered Energy during the First Contract Year, during hour j (expressed in MWh), provided that if such Base Delivered Energy for hour j plus the Availability Tolerance for hour j equals or exceeds Base Requested Energy for hour j, BDEj shall be deemed to be equal to BREj; and (ii) for each subsequent Contract Year, Base Delivered Energy during hour j (expressed in MWh), provided that if Base Delivered Energy for hour j plus the Availability Tolerance for hour j equals or exceeds Base Requested Energy for hour j, BDEj shall be deemed to be equal to BREj.
BREj	=	(i) For the First Contract Year, the sum of Base Requested Energy (for Shell’s account) during the Pre-Term Period during hour j plus Base Requested Energy during the First Contract Year), during hour j (expressed in MWh); and (ii) for each subsequent Contract Year, Base Requested Energy during hour j (expressed in MWh).

If the denominator of the fraction in the formula set forth above for any Off Peak Availability Measurement Period is less than the product of (a) 2000 hours multiplied by (b) the weighted average Contract Capacity during such Off Peak Availability Measurement Period (such product, the “Off Peak Request Shortfall”), the denominator of such fraction for such Off Peak Availability Measurement Period shall be increased by an amount equal to the Off Peak Request Shortfall for such Off Peak Availability Measurement Period and the numerator of such fraction shall be increased by an amount equal to the Off Peak Request Shortfall multiplied by the Off Peak Availability Target for such Off Peak Availability Measurement

Exhibit 8.8-2

Period.

2. Off Peak Availability Payments

For any Off Peak Availability Measurement Period in which the Off Peak Availability Factor is less than the Off Peak Availability Target, the Off Peak Availability Payment for such Off Peak Availability Measurement Period shall be calculated as follows:

Exhibit 8.8-2

Where:
OPAPm	=	Off Peak Availability Payment for Off Peak Availability Measurement Period m (expressed in Dollars), but in no event less than zero.
OPATm	=	Off Peak Availability Target for Off Peak Availability Measurement Period m.
OPAFm	=	Off Peak Availability Factor for Off Peak Availability Measurement Period m.
CPm	=	Total Capacity Payments required to be made by Gulf Power to Shell in the Contract Year in which Off Peak Availability Measurement Period m occurs, which Capacity Payments shall be determined taking into account any adjustment under Section 4.1(b) but without regard to any adjustments under Section 4.1(c) or 4.1(d).

Exhibit 8.8-2

EXHIBIT 10.1

FORM OF LETTER OF CREDIT

________, 20__

[Name and Address

of Beneficiary]

Dear Sirs:

We hereby establish in your favor, for the account of [NAME AND ADDRESS OF ACCOUNT PARTY] (“[Account Party]”), with respect to the Contract for the Purchase of Firm Capacity and Energy of even date herewith between [Account Party] and you (“Beneficiary”) (the “PPA”), our irrevocable standby letter of credit no.  (the “Standby Letter of Credit”) whereby we hereby irrevocably authorize you to draw on us, in accordance with the terms and conditions hereinafter set forth, by your draft or drafts at sight, an amount not to exceed ________________________ United States Dollars (U.S. $_________).

Funds against this Standby Letter of Credit are available to you against your sight draft(s) drawn on us, referring thereon to the number and date of this Standby Letter of Credit, accompanied by a written and completed certificate executed by you in the form attached as Annex 1 hereto, with appropriate insertions. Multiple, partial drafts may be drawn hereunder. Such available funds shall not directly or indirectly constitute funds or collateral deposited with or for the bank account by the [Account Party], or pledged with or for the bank’s account by the [Account Party].

Presentation of such drafts, and such certificates shall be made on any day which is a Business Day, as defined hereinafter for us at or prior to 5:00 p.m. (eastern prevailing time) at our office located at ______________, or at any other office in the United States of America which may be designated by us in a written notice delivered to you. If such sight draft and such certificate are received at either such office, all in strict conformity with the terms and conditions of this Standby Letter of Credit, on or prior to the expiration date hereof, we hereby agree with you that we will duly honor the same within three (3) Business Days of such presentation. Notwithstanding the foregoing, Beneficiary may demand payment under this Standby Letter of Credit by facsimile. Originals of documents presented via facsimile need not be presented. The original of this Standby Letter of Credit and all original amendments, if any, may be mailed thereafter.

For the purpose of this Standby letter of Credit, a “Business Day” shall be defined as a day other than Saturday, Sunday or a day on which banks in [_______, ________] are authorized or required to close.

This Standby Letter of Credit is effective immediately and expires at 5:00 p.m. (eastern prevailing time) on _______, 20__. However, it is a condition of this Standby Letter of Credit that it

Exhibit 10.1-1

will be deemed automatically extended for successive periods of one year each from the present or any future expiration date but in no event later than _______, 20__(the “Final Expiration Date), unless we send you notification in writing, by certified or registered mail (return receipt requested) or overnight courier, at your respective addresses, not less than ninety (90) days prior to any such date, that we have elected not to extend such expiration date for any such additional period. Notwithstanding Article 17 of the UCP (as such term is defined below) , if the expiration of this Standby Letter of Credit falls during an interruption of business described in said Article 17, we agree to extend such expiration date to a date thirty (30) days after the resumption of our normal business.

We hereby undertake that we will not modify, revoke or terminate this Standby Letter of Credit without your written consent. Except as stated herein, payment of drafts drawn under this Standby Letter of Credit is not subject to any condition or qualification. This Standby Letter of Credit sets forth in full the terms of our undertaking, and such undertaking shall not be modified, annulled or amplified by reference to any other document, instrument or agreement referred to herein or in which the Standby Letter of Credit is referred or to which the Standby Letter of Credit relates, and any such reference shall not be deemed to incorporate herein by reference any document, instrument or agreement. Our obligations hereunder are primary obligations that shall not be affected by the performance or non-performance by [Account Party] of any obligations under any loan agreement or under any agreement between [Account Party] and you or between [Account Party] and us or between [Account Party] and its agents.

We hereby waive any right to set off and apply any and all deposits (general or special, time or demand, provisional or final) or collateral at any time held and other indebtedness at any time owing by us to or for the credit of or the account of [Account Party] against any and all of the obligations of [Account Party] now or hereafter existing to reimburse us for our disbursements under this Standby Letter of Credit; provided, however, that each such right shall be reinstated if it is determined that such right would not lead to our being released, prevented or restrained from or delayed in, honoring any draft presented in accordance with this Standby Letter of Credit. The foregoing waiver is intended to defeat any possible claim that honor of this Standby Letter of Credit, or of any draft presented hereunder, may constitute a preferential transfer of the bankrupt account party’s property securing our right of reimbursement. Nothing herein shall be construed to support the validity of any such claim, to support any delay in our obligation to honor this Standby Letter of Credit or to detract from the independence of our obligation to honor this Standby Letter of Credit at the times and in accordance with the terms stated and incorporated by reference herein.

This Standby Letter of Credit is transferable in its entirety (but not in part). Each letter of credit issued upon any such transfer and assignment may be successively transferred and assigned. Transfer of this Standby Letter of Credit to any transferee shall be affected by the presentation to us of the original of this Standby Letter of Credit and all original amendments, if any, when accompanied by our Request to Transfer a certificate in the form as attached hereto as Annex 2, along with your payment for our usual and customary charges/fees for same, as specified in the said form.

Per laws of the United States and the regulations of the U.S. Treasury Department, the Department of Commerce and the Office of Foreign Asset Control, any request to transfer this Standby letter of Credit to any party in violation of such laws and/or regulations is strictly prohibited and will not be

Exhibit 10.1-2

honored.

To the extent not contrary to the express terms hereof, this Standby Letter of Credit shall be governed by the Uniform Customs and Practice for Documentary Credits (1993 Revision), International Chamber of Commerce Publication No. 500 (herein referred to as the “UCP”), or by subsequent Uniform Customs and Practice as may be adopted from time to time by the International Chamber of Commerce. This Standby Letter of Credit shall be deemed to be a contract made under the laws of the State of Florida and shall, as to matters not governed by the UCP, be governed by and construed in accordance with the laws of the [State of New York.]

Yours very truly,

[ISSUING BANK]

Exhibit 10.1-3

ANNEX 1

CERTIFICATE

Re: Contract for the Purchase of Firm Capacity and Energy dated _________, 20__ between [Name of Account Party] (“[Account Party]”) and [Name of Beneficiary] (“[Beneficiary]”) (the “PPA”).

The undersigned, each a duly authorized officer of [Beneficiary], hereby certify to [ISSUING BANK] (the “Bank”) with reference to irrevocable standby letter of credit no.  (the “Standby Letter of Credit”), issued by the Bank for the account of [Account Party] in favor of [Beneficiary] that:

(1) (Insert one of the following, as applicable)

Pursuant to the provisions of the PPA, an event has occurred under the PPA that entitles Beneficiary to draw on the Standby Letter of Credit in the amount of the sight draft (an example of such an event includes, without limitation, an Event of Default described in the PPA).

or

[Beneficiary] has received written notice from the Bank in accordance with the terms of the Standby Letter of Credit that the Bank has elected not to extend the expiration date of the Standby Letter of Credit for an additional period past its then-expiration date.

(2)       The undersigned are each a duly elected and incumbent officer of [Beneficiary] and are authorized to execute and deliver this certificate and to draw upon the Standby Letter of Credit.

IN WITNESS WHEREOF, the undersigned have executed and delivered this Certificate as of this day of , 20.

[BENEFICIARY]

By:

Title:

By:

Title:

Exhibit 10.1-4

ANNEX 2

INSTRUCTION TO ASSIGN IN ENTIRETY

, 20

___________________________

Re: Irrevocable Standby Letter of Credit No.

Gentlemen:

For value received, the undersigned beneficiary hereby irrevocably assigns to:

(Name of Assignee)

(Address)

all rights of the undersigned beneficiary to draw under the above Standby Letter of Credit in its entirety.

By this assignment, all rights of the undersigned beneficiary in such Standby Letter of Credit are transferred to the assignee and the assignee shall hereafter have the sole rights as beneficiary thereof.

The Standby Letter of Credit is returned herewith and in accordance therewith we ask you to issue a new irrevocable Standby Letter of Credit in favor of the assignee with provisions consistent with the Standby Letter of Credit.

Very truly yours

[Beneficiary]

By:

Title:

By:

Title:

Exhibit 10.1-5

EXHIBIT 10.2

Form of Guaranty

THIS GUARANTY AGREEMENT (the “Guaranty”), dated and effective as of ___________, 20__, is made and entered into by __________________ (the “Guarantor”) in favor of the __________________ (the “Beneficiary”).

WHEREAS Beneficiary and ____________________ (the “Company”), [a subsidiary of the Guarantor], have entered into that certain Power Purchase Agreement dated as of ____________, 20__ (the “Agreement”);

WHEREAS, the Beneficiary has required, as an inducement to enter into the Agreement, that Guarantor deliver to the Beneficiary this Guaranty or other Eligible Collateral when required under the Agreement;

WHEREAS, the Guarantor qualifies as a Seller or Buyer Guarantor as the case may be under the Agreement and this Guaranty qualifies as Eligible Collateral under the Agreement; and

WHEREAS, the Guarantor will derive substantial direct and indirect benefit from the transactions contemplated by the Agreement.

NOW, THEREFORE, for and in consideration of the foregoing premises, the mutual agreements contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Guarantor agrees as follows:

ARTICLE 1 - DEFINITIONS

1.1       Definitions. Unless otherwise defined in this Guaranty, capitalized terms have the meanings specified or referred to in the Agreement.

ARTICLE 2 - GUARANTY

2.1       Guaranty. Guarantor hereby unconditionally and irrevocably guarantees to the Beneficiary and its successors and assigns, the prompt and full payment of any and all obligations of the Company to the Beneficiary when due, whether by acceleration or otherwise, with such interest as may accrue thereon, under the Agreement or under any other documents or instruments now or hereafter evidencing, securing or otherwise relating to the Agreement (the “Guaranteed Obligations”); provided, however, that Guarantor’s liability under this Guaranty shall in no event exceed the amount of Eligible Collateral required to be provided by Seller from time to time pursuant to Section 7.1 of the Agreement. If Company fails to pay or any Guaranteed Obligation, then Guarantor will immediately pay such obligation upon demand by the Beneficiary. Guarantor shall not be liable for consequential, exemplary, equitable, lost profits, punitive or other damages except as specifically provided in the Agreement to be due.

2.2       Guaranty Absolute. (a) The Guarantor absolutely guarantees that the Guaranteed Obligations will be paid and strictly in accordance with the terms of the Agreement, regardless of

Exhibit 10.2-6

any law or regulation now or hereafter in effect in any jurisdiction affecting any of such terms or the rights of the Beneficiary with respect thereto. This Guaranty constitutes a guarantee of payment and not of collection. The obligations of the Guarantor hereunder are several from the Company or any other person, and are primary obligations concerning which the Guarantor is the principal obligor. The liability of Guarantor under this Guaranty shall be direct and immediate and not conditional or contingent upon the pursuit of any remedies against the Company or any other person, nor against securities or liens available to the Beneficiary, its successors or assigns. The liability of the Guarantor under this Guaranty shall be irrevocable, absolute and unconditional irrespective of, and the Guarantor hereby irrevocably waives any defenses it may now have or hereafter acquire in any way relating to, any or all of:

(i) any change in the time, manner or place of payment of, or in any other term of, all or any of the Guaranteed Obligations, or any other amendment, modification or waiver of, or any consent to departure from, the terms of such Guaranteed Obligations;

(ii) any change, restructuring or termination of the corporate structure or existence of the Company or any of its subsidiaries;

(iii) any lack of validity or enforceability of the Agreement or any agreement or instrument relating thereto;

(iv) any failure of the Beneficiary to disclose to either the Company or the Guarantor any information relating to the business, condition (financial or otherwise), operations, performance, properties or prospects of either the Company or any of its subsidiaries now or hereafter known to the Beneficiary (the Guarantor waiving any duty on the part of the Beneficiary to disclose such information);

(v) any failure of the Beneficiary to commence an action against Company;

(vi) any lack of due diligence by the Beneficiary in the collection or protection of or realization upon any collateral securing the Guaranteed Obligations; or

(vii) any circumstance whatsoever (including, without limitation, any statute of limitations) or any act of the Beneficiary or any existence of or reliance on any representation by the Beneficiary that might otherwise constitute a legal or equitable defense available to, or a discharge of, the Guarantor.

This Guaranty shall continue to be effective or be reinstated, as the case may be, if at any time any payment of any of the Guaranteed Obligations is rescinded or must otherwise be returned by the Beneficiary or any other Person upon the insolvency, bankruptcy, or reorganization of the Company, all as though such payment had not been made.

(b)       No action which the Beneficiary shall take or fail to take in connection with the Guaranteed Obligations, or any security for the payment or performance of any of the Guaranteed Obligations, nor any course of dealing with Company or any other person, shall release Guarantor’s

Exhibit 10.2-7

obligations hereunder, affect this Guaranty in any way, or afford Guarantor any recourse against the Beneficiary. 

(c)       In the case of an Event of Default under the Agreement or with regard to any of the Guaranteed Obligations, Guarantor hereby consents and agrees that the Beneficiary shall have the right to enforce its rights, powers, and remedies thereunder or hereunder or under any other instrument now or hereafter evidencing, securing, or otherwise relating to the Guaranteed Obligations, and apply any payments or credits received by the Company or Guarantor or realized from any security, in any manner and in any order as the Beneficiary, in its sole discretion, shall see fit, and all rights, powers, and remedies available to the Beneficiary in such event shall be nonexclusive and cumulative of all other rights, powers, and remedies provided thereunder or hereunder or by law or in equity.  No election of remedies by Beneficiary shall release or limit Guarantor’s liability to Beneficiary hereunder, even if the effect of the election is to deprive Guarantor of its subrogation to Beneficiary’s rights or its right to reimbursement from customers for sums paid by Guarantor.

2.3       Waivers and Acknowledgments. (a) Guarantor hereby waives promptness, diligence, presentment, demand of payment, acceptance, notice of acceptance, protest, notice of dishonor and any other notices with respect to any of the Guaranteed Obligations and this Guaranty.

(b)       The Guarantor hereby unconditionally and irrevocably waives any right to revoke this Guaranty and acknowledges that this Guaranty is continuing in nature and applies to all Guaranteed Obligations, whether existing now or in the future. The provisions of this Guaranty shall extend and be applicable to all renewals, amendments, extensions, consolidations, and modifications of the Agreement.

(c)       The Guarantor hereby unconditionally and irrevocably waives any defense based on any right of set-off or counterclaim against or in respect of the obligations of the Guarantor hereunder; provided, however, that Guarantor shall have the same defenses available to the Company with respect to any payment obligations arising under the Agreement, except for defenses arising out of bankruptcy, insolvency, dissolution or liquidation of the Company or the lack of power or authority of the Company to enter into and/or perform the Agreement.

2.4       Subrogation. Notwithstanding any payment or payments or performance made by the Guarantor hereunder, the Guarantor hereby irrevocably waives any and all rights of subrogation to the rights of the Beneficiary against the Company and any and all rights of reimbursement, assignment, indemnification or implied contract or any similar rights (including without limitation any statutory rights of subrogation under Section 509 of the Bankruptcy Code, 11 U.S.C. § 509) against the Company or against any other guarantor of all or any part of the Guaranteed Obligations until such time as the Guaranteed Obligations have been indefeasibly paid or performed in full. If, notwithstanding the foregoing, any amount shall be paid to the Guarantor on account of such subrogation or similar rights at any time when all of the Guaranteed Obligations shall not have been indefeasibly paid in full, such amount shall be held by the Guarantor in trust for the Beneficiary and shall be turned over to the Beneficiary in the exact form received by the Guarantor, to be applied against the Guaranteed Obligations in such order as the Beneficiary may determine in its sole discretion.

Exhibit 10.2-8

ARTICLE 3 - REPRESENTATIONS AND WARRANTIES

The Guarantor hereby represents and warrants as follows:

3.1       Organization. The Guarantor is a [_______] duly organized, validly existing and in good standing under the laws of the state of [_______].

3.2       Authorization; No Conflict. The execution and delivery by the Guarantor of this Guaranty, and the performance by the Guarantor of its obligations hereunder (i) are within the Guarantor’s [_______] powers, (ii) have been duly authorized by all necessary [_______] action, (iii) do not contravene its [_______] or any law or regulation applicable to or binding on the Guarantor or any of its properties and (iv) do not require the consent or approval of any person which has not already been obtained or the satisfaction or waiver of any conditions precedent to the effectiveness of this Guaranty that have not been satisfied or waived.

3.3       Enforceability. This Guaranty constitutes the legal, valid and binding obligation of the Guarantor enforceable against the Guarantor in accordance with its terms, except to the extent that such enforceability may be limited by applicable bankruptcy, insolvency, dissolution, reorganization, moratorium, liquidation or other similar laws affecting creditors’ rights generally and by general principles of equity (regardless of whether enforcement is sought in a proceeding in equity or at law).

3.4       No Bankruptcy Proceedings. There are no bankruptcy proceedings pending or being contemplated by Guarantor or, to its knowledge, threatened against it.

3.5       No Legal Proceedings. There are no legal proceedings that would be reasonably likely to materially adversely affect Guarantor’s ability to perform this Guaranty.

ARTICLE 4 - MISCELLANEOUS

4.1       Continuing Guaranty; Assignment. This Guaranty is a continuing guaranty and shall (i) remain in full force and effect until all of the Guaranty Obligations have been satisfied, (ii) consistent with the terms hereof, apply to all Guaranteed Obligations whenever arising, (iii) be binding upon the Guarantor, its successors and assigns, and (iv) inure to the benefit of, and be enforceable by, the Beneficiary and its permitted assignees hereunder. The Beneficiary may not assign or delegate its rights or obligations under this Guaranty without the prior written consent of the Guarantor, which consent shall not be unreasonably delayed or withheld. The Guarantor may not assign or delegate its rights or obligations under this Guaranty without (x) the prior written consent of the Beneficiary, which consent may be withheld in the Beneficiary’s sole discretion, and (y) a written assignment and assumption agreement in form and substance reasonably acceptable to the Beneficiary. Without prejudice to the survival of any of the other agreements of the Guarantor under this Guaranty, the agreements and obligations of the Guarantor contained in Section 4.4 (with respect to enforcement expenses) and the last sentence of Section 2.2(a) shall survive the payment in full of the Guaranteed Obligations and all of the other amounts payable under this Guaranty.

4.2       Notices. All notices, requests, demands and other communications which are required or may be given under this Guaranty shall be in writing and shall be deemed to have been duly given

Exhibit 10.2-9

when actually received if (a) personally delivered; (b) transmitted by facsimile, electronic or digital transmission method; or (c) if sent by certified or registered mail, return receipt requested. In each case notice shall be sent:

(i) if to the Beneficiary:

[Company, address, c/o person]

(ii) if to the Guarantor:

[Company, address, c/o person]

or to such other place and with such other copies as the Beneficiary or the Guarantor may designate as to itself by written notice to the other pursuant to this Section 4.2. Delivery by facsimile of an executed counterpart of a signature page to any amendment or waiver of any provision of this Guaranty shall be effective as delivery of an original executed counterpart thereof.

4.3       Delay and Waiver. Except as to the applicable statute of limitations, no failure on the part of the Beneficiary to exercise, and no delay in exercising, any right hereunder shall operate as a waiver thereof; nor shall any single or partial exercise of any right hereunder preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law.

4.4      Expenses. The Guarantor agrees to pay or reimburse the Beneficiary and any permitted assignees of the Beneficiary on demand for its reasonable costs, charges and expenses (including reasonable fees and expenses of counsel) incurred in connection with the enforcement of this Guaranty or occasioned by any breach by the Guarantor of any of its obligations under this Guaranty should Guarantor be required to pay under this Guaranty.

4.5       Entire Agreement; Amendments. This Guaranty and any agreement, document or instrument attached hereto or referred to herein integrate all the terms and conditions mentioned herein or incidental hereto and supersede all oral negotiations and prior writings in respect to the subject matter hereof. In the event of any conflict between the terms, conditions and provisions of this Guaranty and any such agreement, document or instrument, the terms, conditions and provisions of this Guaranty shall prevail. This Guaranty may only be amended or modified by an instrument in writing signed by each of the Guarantor and the Beneficiary and any permitted assignees of the Beneficiary.

4.6       Headings. The headings of the various Sections of this Guaranty are for convenience of reference only and shall not modify, define or limit any of the terms or provisions hereof.

4.7       Governing Law; Consent to Jurisdiction. (a) This Guaranty shall be construed and interpreted, and the rights of the parties determined, in accordance with the law of the State of Florida, without giving effect to principles of conflicts of law that would require the application of the laws of another jurisdiction.

Exhibit 10.2-10

(b) Each party hereto irrevocably and unconditionally (i) agrees that the exclusive jurisdiction for any suit, action or other legal proceeding arising out of this Guaranty shall be brought in the United States District Court for the Northern District of Florida or in any state court of general jurisdiction in Florida; (ii) consents to the jurisdiction of any such court in any such suit, action or proceeding; and (iii) waives any objection which such party may have to the laying of venue of any such suit, action or proceeding in any such court.

(c) THIS GUARANTEE IS MADE ON THE BASIS THAT GUARANTOR AND BENEFICIARY EACH HEREBY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM (WHETHER BASED ON CONTRACT, TORT OR OTHERWISE) ARISING OUT OF OR RELATING TO, THIS GUARANTY, OR THE ACTIONS OF THE BENEFICIARY IN THE NEGOTIATION, ADMINISTRATION, PERFORMANCE OR ENFORCEMENT THEREOF.

4.8       Severability. Any provision of this Guaranty that shall be prohibited or unenforceable shall be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof.

*****             IN WITNESS WHEREOF, the Guarantor has caused this Guaranty to be duly executed and delivered by its duly authorized representative as of the day and year first above written.

[Company]

By:

Name:

Title:

Exhibit 10.2-11

EX-24

Exhibit 24(c)2

April 1, 2009

W. Paul Bowers and Wayne Boston

Dear Sirs:

As an officer of Georgia Power Company, I hereby make, constitute, and appoint each of you my true and lawful Attorney in my name, place and stead, to sign and cause to be filed with the Securities and Exchange Commission (1) this Company's Quarterly Reports on Form 10-Q during 2009, and (2) any necessary or appropriate amendment or amendments to any such reports and to this Company’s Annual Report on Form 10-K for the year ended December 31, 2008, each such report or amendments to such reports to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,

/s/Ronnie R. Labrato

Ronnie R. Labrato

EX-31

Exhibit 31(a)1

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, David M. Ratcliffe, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2009

/s/David M. Ratcliffe

David M. Ratcliffe

Chairman, President and Chief Executive Officer

EX-31

Exhibit 31(a)2

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, W. Paul Bowers, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2009

/s/W. Paul Bowers

W. Paul Bowers

Executive Vice President and Chief Financial Officer

EX-31

Exhibit 31(b)1

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Charles D. McCrary, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2009

/s/Charles D. McCrary

Charles D. McCrary

President and Chief Executive Officer

EX-31

Exhibit 31(b)2

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Art P. Beattie, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2009

/s/Art P. Beattie

Art P. Beattie

Executive Vice President, Chief Financial Officer and Treasurer

EX-31

Exhibit 31(c)1

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Michael D. Garrett, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2009

/s/Michael D. Garrett

Michael D. Garrett

President and Chief Executive Officer

EX-31

Exhibit 31(c)2

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Ronnie R. Labrato, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2009

/s/Ronnie R. Labrato

Ronnie R. Labrato

Executive Vice President, Chief Financial Officer and Treasurer

EX-31

Exhibit 31(d)1

GULF POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Susan N. Story, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Gulf Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2009

/s/Susan N. Story

Susan N. Story

President and Chief Executive Officer

EX-31

Exhibit 31(d)2

GULF POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Philip C. Raymond, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Gulf Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2009

/s/Philip C. Raymond

Philip C. Raymond

Vice President and Chief Financial Officer

EX-31

Exhibit 31(e)1

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Anthony J. Topazi, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2009

/s/Anthony J. Topazi

Anthony J. Topazi

President and Chief Executive Officer

EX-31

Exhibit 31(e)2

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Frances Turnage, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2009

/s/Frances Turnage

Frances Turnage

Vice President, Treasurer and Chief Financial Officer

EX-31

Exhibit 31(f)1

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Ronnie L. Bates, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2009

/s/Ronnie L. Bates

Ronnie L. Bates

President and Chief Executive Officer

EX-31

Exhibit 31(f)2

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Michael W. Southern, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2009

/s/Michael W. Southern

Michael W. Southern

Senior Vice President, Treasurer and Chief Financial Officer

EX-32

Exhibit 32(a)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of The Southern Company for the quarter ended March 31, 2009, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)	such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended March 31, 2009, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended March 31, 2009, fairly presents, in all material respects, the financial condition and results of operations of The Southern Company.

/s/David M. Ratcliffe

David M. Ratcliffe

Chairman, President and

Chief Executive Officer

/s/W. Paul Bowers

W. Paul Bowers

Executive Vice President and

Chief Financial Officer

Date: May 7, 2009

EX-32

Exhibit 32(b)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended March 31, 2009, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)	such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended March 31, 2009, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended March 31, 2009, fairly presents, in all material respects, the financial condition and results of operations of Alabama Power Company.

/s/Charles D. McCrary

Charles D. McCrary

President and Chief Executive Officer

/s/Art P. Beattie

Art P. Beattie

Executive Vice President,

Chief Financial Officer and Treasurer

Date: May 7, 2009

EX-32

Exhibit 32(c)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended March 31, 2009, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)	such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended March 31, 2009, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended March 31, 2009, fairly presents, in all material respects, the financial condition and results of operations of Georgia Power Company.

/s/Michael D. Garrett

Michael D. Garrett

President and Chief Executive Officer

/s/Ronnie R. Labrato

Ronnie R. Labrato

Executive Vice President,

Chief Financial Officer and Treasurer

Date: May 7, 2009

EX-32

Exhibit 32(d)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended March 31, 2009, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)	such Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended March 31, 2009, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in such Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended March 31, 2009, fairly presents, in all material respects, the financial condition and results of operations of Gulf Power Company.

/s/Susan N. Story

Susan N. Story

President and Chief Executive Officer

/s/Philip C. Raymond

Philip C. Raymond

Vice President and Chief Financial Officer

Date: May 7, 2009

EX-32

Exhibit 32(e)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended March 31, 2009, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)	such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended March 31, 2009, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended March 31, 2009, fairly presents, in all material respects, the financial condition and results of operations of Mississippi Power Company.

/s/Anthony J. Topazi

Anthony J. Topazi

President and Chief Executive Officer

/s/Frances Turnage

Frances Turnage

Vice President, Treasurer and

Chief Financial Officer

Date: May 7, 2009

EX-32

Exhibit 32(f)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended March 31, 2009, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)	such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended March 31, 2009, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended March 31, 2009, fairly presents, in all material respects, the financial condition and results of operations of Southern Power Company.

/s/Ronnie L. Bates

Ronnie L. Bates

President and Chief Executive Officer

/s/Michael W. Southern

Michael W. Southern

Senior Vice President, Treasurer and

Chief Financial Officer

Date: May 7, 2009