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Georgia Power Company’s 2013 Integrated Resource Plan 

and Application for Decertification of Plant Branch Units 3 and 4, 

Plant McManus Units 1 and 2, Plant Kraft Units 1-4, Plant Yates 

Units 1-5, Plant Boulevard Units 2 and 3, and Plant Bowen Unit 6 

Main Document

TABLE OF CONTENTS

Page

SECTION 1 - SUMMARY OF 2013 INTEGRATED RESOURCE PLAN............................. 1

1.1 FOREWORD......................................................................................................... 3

1.2 INTRODUCTION ............................................................................................... 12

1.3 THE 2010 IRP...................................................................................................... 13

1.4 SIGNIFICANT RECENT DEVELOPMENTS ................................................... 13

1.4.1 Georgia Power Advanced Solar Initiative ............................................... 14

1.4.2 Plant McDonough-Atkinson Units 4-6 .................................................... 14

1.4.3 Plant Vogtle Units 3 and 4....................................................................... 15

1.4.4 Wholesale to Retail Actions..................................................................... 15

1.4.5 Reduced Fuel Rates.................................................................................. 15

1.4.6 DSM Program Implementation................................................................ 16

1.5 THE SUPPLY-SIDE PLAN ................................................................................ 16

1.5.1 MATS Compliance Strategy Update ....................................................... 16

1.5.2 Unit Retirements...................................................................................... 18

1.6 THE DEMAND-SIDE PLAN.............................................................................. 21

1.7 THE PRICING PLAN ......................................................................................... 22

1.8 THE ENVIRONMENTAL PLAN....................................................................... 23

1.9 RELIABILITY..................................................................................................... 23

1.10 RESERVE MARGINS ........................................................................................ 24

1.11 THE DEMAND AND ENERGY FORECASTS................................................. 24

1.12 TRANSMISSION PLAN..................................................................................... 25

1.13 INTEGRATED RESOURCE PLAN................................................................... 25

1.14 CONCLUSION.................................................................................................... 27
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SECTION 2 - INTEGRATED RESOURCE PLANNING PROCESS OVERVIEW............. 29

2.1 CRITERIA FOR RESOURCE SELECTION...................................................... 32

2.2 OUTLINE OF THE PROCESS........................................................................... 33

2.2.1 Development of the Benchmark Plan ...................................................... 34

2.2.1.1 Data Inputs................................................................................ 34

2.2.1.2 Mix Process............................................................................... 36

2.2.2 Assessment of Demand-Side Programs................................................... 36

2.2.3 Existing Resource Evaluation.................................................................. 37

2.2.4 Integration and Development of the IRP ................................................. 37

SECTION 3 - BUDGET 2013 LOAD AND ENERGY FORECAST .................................... 39

3.1 GENERAL FORECASTING AND ECONOMICS OVERVIEW...................... 41

3.2 FORECAST ASSUMPTIONS AND METHODS .............................................. 42

SECTION 4 - COMPARISON OF THE FORECAST WITH EXISTING

RESOURCES ................................................................................................... 45

4.1 SYSTEM AND GEORGIA POWER RESOURCES.......................................... 47

SECTION 5 - DEMAND-SIDE PLAN................................................................................... 49

5.1 REVIEW OF SIGNIFICANT EVENTS SINCE PREVIOUS IRP FILING ....... 51

5.1.1 2010 IRP Filing Approval........................................................................ 51

5.1.2 Program Evaluation Results..................................................................... 52

5.1.3 2013 IRP Demand Side Management Working Group 

(“DSMWG”) Meetings............................................................................ 52

5.1.4 2013 Nine Step DSM Planning Process................................................... 52

5.1.5 2013 IRP Avoided Cost/Fuel Price Decreases......................................... 55

5.2 DISCUSSION OF CURRENT AND PROPOSED DSM PROGRAMS ............ 55

5.2.1 Continuation and Expansion of Current Certified DSM Programs 

and Addition of New Certified DSM Program........................................ 55

5.2.1.1 Residential DSM Programs....................................................... 55

5.2.1.2 Commercial DSM Programs..................................................... 59

5.2.2 Continuation of the Weatherization Assistance for Low Income 

Customers Program.................................................................................. 62

5.2.3 Energy Efficiency Information Programs................................................ 62

5.2.4 Energy Audits, Energy Efficiency Information Line and One-OnOne Energy Efficiency Assistance........................................................... 62

5.2.5 Energy Efficiency Awareness Initiative .................................................. 63
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5.2.6 Demand Response Tariffs........................................................................ 64

5.3 DSM RESOURCE ASSESSMENT AND INITIAL COST 

EFFECTIVENESS SCREENING ....................................................................... 64

5.3.1 Assessment and Screening Methodology ................................................ 64

5.3.2 DSM Program Economic Screening Policy............................................. 65

5.3.3 Data Development ................................................................................... 66

5.3.3.1 Residential Technology ............................................................ 67

5.3.3.2 Commercial Technology........................................................... 67

5.3.3.3 Industrial Technology ............................................................... 68

5.3.4 Economic Screening ................................................................................ 68

5.4 DEMAND-SIDE PROGRAM DEVELOPMENT .............................................. 69

5.4.1 Demand-Side Resource Policy ................................................................ 69

5.4.2 10-Year DSM Program Plans .................................................................. 70

5.5 REGULATORY TREATMENT OF DSM PROGRAM COSTS AND 

THE ADDITIONAL SUM .................................................................................. 70

5.6 SUMMARY OF DSM CASES............................................................................ 71

5.6.1 Proposed Case – Georgia Power Recommended Case ............................ 71

5.6.2 DSMWG Advocacy Sensitivity Case – All Program Concepts 

Identified with DSMWG Subgroup......................................................... 72

5.6.3 Aggressive Sensitivity Case..................................................................... 72

SECTION 6 - SUPPLY-SIDE PLAN...................................................................................... 75

6.1 OVERVIEW ........................................................................................................ 77

6.2 EXISTING GENERATING PLANT OPTIONS................................................. 77

6.2.1 Previous Resource Commitments............................................................ 77

6.2.2 Installation of Environmental Controls for Plant Bowen Units 1-4, 

Plant Wansley Units 1 and 2, Plant Scherer Units 1-3 and Plant 

Hammond Units 1-4 to Allow for Continued Operation ......................... 78

6.2.3 Switching Primary Fuels at Plant Mitchell Unit 3, Plant Yates 

Units 6 and 7, Plant McIntosh Unit 1, and Plant Gaston Units 1-4 

to Allow for Continued Operation ........................................................... 78

6.2.4 Decertification of Plant Branch Units 3 and 4, Plant McManus 

Units 1 and 2, Plant Kraft Units 1-4, Plant Yates Units 1-5, Plant 

Boulevard Units 2 and 3, and Plant Bowen Unit 6.................................. 79

6.2.5 Blackstart Resources and Transmission System Restoration Plan .......... 81

6.3 SUPPLY-SIDE OPTIONS .................................................................................. 81
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6.4 NEW GENERATING TECHNOLOGIES .......................................................... 81

6.4.1 Preliminary Screening.............................................................................. 82

6.4.2 Detailed Screening................................................................................... 82

6.4.3 Nuclear Generation .................................................................................. 83

6.4.4 Generation Mix Candidate Selections ..................................................... 83

6.5 SUPPLY-SIDE PLAN......................................................................................... 83

6.5.1 Base Case Assumptions........................................................................... 84

6.5.2 Benchmark Plan Results.......................................................................... 85

6.5.3 Reference Case Sensitivities.................................................................... 85

SECTION 7 - INTEGRATION OF DEMAND-SIDE PROGRAMS INTO THE 

BENCHMARK SUPPLY-SIDE PLAN .............................................................. 89

7.1 INTRODUCTION ............................................................................................... 91

7.2 DISTRIBUTING CAPACITY AMONG THE OPERATING 

COMPANIES ...................................................................................................... 91

SECTION 8 - INTEGRATED RESOURCE PLAN................................................................ 93

8.1 OVERVIEW ........................................................................................................ 95

8.2 INTEGRATED RESOURCE PLAN................................................................... 95

8.3 PLAN REVIEW BASED ON OTHER PLANNING OBJECTIVES ................. 96

SECTION 9 - SUMMARY OF TRANSMISSION PLAN ..................................................... 99

9.1 TRANSMISSION PLAN................................................................................... 101

9.2 TRANSMISSION PLANNING PRINCIPLES ................................................. 101

9.3 10 YEAR TRANSMISSION PLAN.................................................................. 102

SECTION 10 - RENEWABLE RESOURCES ....................................................................... 105

10.1 RENEWABLE RESOURCES OVERVIEW .................................................... 107

10.2 GREEN ENERGY PROGRAM ........................................................................ 107

10.2.1 Distributed Generation Energy Purchases............................................. 109

10.2.2 Community Supported Projects and Capacity Exceptions .................... 111

10.3 OVERVIEW OF ADDITIONAL SOLAR INITIATIVES................................ 112

10.3.1 Large Scale Solar................................................................................... 113

10.3.2 Georgia Power Advanced Solar Initiative ............................................. 114

10.3.3 Distributed Solar Demonstration Projects ............................................. 115

10.3.4 1 MW Solar Self-Build Demonstration ................................................. 117

10.3.5 EPRI Distributed Photovoltaic (DPV) Project....................................... 118
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10.3.6 Solar PV Tracking and Orientation Study ............................................. 118

10.3.7 Concentrating Solar Thermal Applications Research............................ 119

10.3.8 Solar Water Heating Demonstration Projects........................................ 119

10.3.9 Additional Solar Related Resources Available to Customers................ 120

10.4 90 MW RENEWABLE SELF-BUILD PROJECT............................................ 120

10.5 BIOMASS OVERVIEW ................................................................................... 121

10.5.1 Biomass Cofiring ................................................................................... 121

10.5.2 Plant Mitchell Unit 3 Biomass Conversion .......................................... 123

10.6 WIND ENERGY ............................................................................................... 124

10.6.1 Proposed Small Wind Demonstration Pilot Project............................... 125

10.6.2 Georgia Coast Offshore Wind Feasibility Study ................................... 125

10.6.3 Gulf Coast Wind Measurement Project ................................................. 126

10.6.4 Off-System Wind Projects..................................................................... 126

10.7 INCREMENTAL HYDRO OVERVIEW ......................................................... 127

SECTION 11 - HYDRO ELECTRIC OPERATION AND RE-LICENSING........................ 129

11.1 FOREWORD..................................................................................................... 131

11.2 GEORGIA POWER HYDRO PLANT RE-LICENSING SCHEDULE........... 131

11.3 REQUIREMENTS AND RISK TO RE-LICENSING REQUIREMENTS ...... 133

SECTION 12 - WHOLESALE GENERATION..................................................................... 135

12.1 OVERVIEW ...................................................................................................... 137

12.2 WHOLESALE CAPACITY TO RETAIL......................................................... 137

12.3 WHOLESALE REQUIREMENTS CONTRACTS .......................................... 138

12.4 FLINT EMC CONTRACTS.............................................................................. 138

SECTION 13 - ACTION PLAN.............................................................................................. 141

SECTION 14 - ATTACHMENTS .......................................................................................... 147

ATTACHMENT 14.1 – MAJOR MODELS USED IN IRP ......................................... 149

ATTACHMENT 14.2 – TECHNOLOGY SCREENING ............................................. 154

ATTACHMENT 14.3 – SUMMARY OF THE SYSTEM POOLING 

ARRANGEMENT............................................................................................. 167

ATTACHMENT 14.4 – RESEARCH ACTIVITIES .................................................... 174

TAB 1—Application for Decertification of Plant Branch Units 3 and 4, Plant McManus Units 1 

and 2, Plant Kraft Units 1-4, Plant Yates Units 1-5, Plant Boulevard Units 2 and 3, and 

Plant Bowen Unit 6
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2013 INTEGRATED RESOURCE PLAN

TECHNICAL APPENDICES INDEX

TECHNICAL APPENDIX VOLUME 1

2013 IRP PLAN & MIX STUDY

GENERATION TECHNOLOGY DATA BOOK

RESERVE MARGIN STUDY

TECHNICAL APPENDIX VOLUME 2

BUDGET 2013 LOAD AND ENERGY FORECAST

ENVIRONMENTAL COMPLIANCE STRATEGY

FINANCIAL REVIEW

UNIT RETIREMENT STUDY

DSM PROGRAM DOCUMENTATION

SELECTED SUPPORTING INFORMATION

TECHNICAL APPENDIX VOLUME 3

TRANSMISSION PLAN
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1 – SUMMARY OF 2013 

INTEGRATED

RESOURCE PLAN
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SECTION 1 - SUMMARY OF 2013 INTEGRATED RESOURCE PLAN

1.1 FOREWORD 

This 2013 Integrated Resource Plan (“2013 IRP”) is the eighth IRP filed by Georgia Power 

Company (“Georgia Power” or the “Company”) since enactment of the Integrated Resource 

Planning Act in 1991, O.C.G.A. § 46-3A-1 et seq. (“IRP Act”), which requires the filing of such 

a plan every three years. This 2013 IRP is the product of a thorough planning process that has 

resulted in a robust and diverse portfolio of generation and demand side resources that will 

continue to provide customers reliable service at rates below the national average. 

The Company filed an updated IRP on August 4, 2011 in Docket No. 34218 (“2011 IRP 

Update”) in connection with its application for the decertification of Plant Branch Units 1 and 2 

and Plant Mitchell Unit 4C and the certification of certain power purchase agreements (“PPAs”) 

identified through the 2015 Request for Proposals (“RFP”). At that time, the Company faced a 

significant amount of uncertainty as it sought to plan for the impact of numerous potential 

environmental regulations, the most significant and immediate of which was the United States 

Environmental Protection Agency’s (“EPA”) Mercury and Air Toxics Standards (“MATS”) rule, 

which had not been finalized at the time of the initial filing. The Company and the Georgia 

Public Service Commission (“Commission”) grappled with a number of difficult decisions in 

light of the potential impact of the MATS rule. Specifically, the Company requested and 

received authorization to proceed with initiation of construction of baghouses that were 

anticipated to be needed at Plants Bowen, Wansley and Hammond to comply with the MATS 

rule and also recommended deferral of decisions concerning 2,600 megawatts (“MW”) of 

generating units. However, the Company asserted that it was reasonable to assume that 2,000 

MW of that capacity would be unavailable in 2015 as a result of the MATS rule. 

Now that the Company has had the opportunity to further analyze and assess the impact of the 

final MATS rule, a significant portion of the uncertainty that framed the discussion in the 2011 

IRP Update has been eliminated, as the Company has developed a compliance plan that will 

maintain long term reliability for customers in a cost-effective manner. As anticipated in the 

2011 IRP Update, the Company will be required to incur significant capital costs to comply with 

the final MATS rule. However, the projected capital costs required for compliance are less than 
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had been anticipated at the time of the 2011 IRP Update. These costs are lower for two primary 

reasons. First, key changes were made to the final rule enabling the Company to lower the cost 

of compliance, thereby benefitting customers. Southern Company, on behalf of Georgia Power 

and its other operating companies, as well as this Commission, played a major role in 

communicating to the EPA the need for changes because of the impacts that the overly stringent

proposed rule could have had on the reliability and affordability of electricity. Second, because 

of these changes in the rule, the Company was able to utilize its and Southern Company’s 

substantial research and development (“R&D”) capabilities and technical expertise to develop 

innovative compliance solutions that were less expensive than previously expected. The 

Company has explored a wide range of compliance options for its generating units. From plant 

to plant, and in some cases from unit to unit, a unique set of compliance options are feasible 

based on factors such as the unit’s design, operating characteristics, existing environmental 

controls, etc.

As has been previously communicated to the Commission, the Company has determined that 

only Plant Bowen Units 3 and 4 will require baghouses at this time. MATS compliance can be 

achieved at Plant Bowen Units 1 and 2, Plant Wansley Units 1 and 2 and Plant Hammond Units 

1–4 with the installation of activated carbon and hydrated lime injection systems, a significantly 

less costly technology than baghouses (an activated carbon and hydrated lime injection system 

will also be required at Plant Bowen Units 3 and 4 in addition to the baghouses). The difference 

between the projected cost to install seven baghouses and the currently projected MATS 

compliance costs equates to a savings of several hundred million dollars for customers. 

Plant Scherer Units 1-3 will also be retrofitted with additional controls in order to ensure MATS 

compliance. Although these units will be well controlled due to installation of the required 

Georgia Multipollutant rule controls, a bromine injection system will be installed in order to 

most cost effectively comply with the MATS requirements. Pending a successful test burn and 

subsequent feasibility study in 2013, the Company also plans to fuel switch Plant McIntosh Unit 

1 from Central Appalachian coal to Powder River Basin (“PRB”) coal to provide additional 

economic benefits to customers. With the projected coal change, Plant McIntosh Unit 1 will 

install an activated carbon and dry sorbent injection system to achieve MATS compliance by 

April 16, 2016.
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The Company’s multi-faceted approach to MATS compliance also includes switching to natural 

gas as the primary fuel at Plant Yates Units 6 and 7 and Plant Gaston Units 1-4. The primary 

fuel for Plant Yates Units 6 and 7 will be switched from coal to natural gas by April 2015 and the 

primary fuel for Plant Gaston will be switched from coal to natural gas by April 2016. 

Unfortunately, the projected costs to comply with the MATS rule, even in its final form, and 

other pending environmental regulations have placed significant pressure on the economic 

viability of several of the Company’s fossil generating units to the point that retirement is the 

most cost-effective approach for these units. Therefore, the Company is seeking decertification 

for Plant Branch Units 3 and 4, Plant McManus Units 1 and 2, Plant Kraft Units 1-4, and Plant 

Yates Units 1-5. These units have a long and distinguished history of service to Georgia Power 

customers and have had a significant positive impact on the communities in which they operate. 

Only after extensive analysis and evaluation (which is a staple of both the Company’s routine 

planning and the iterative IRP process), and after exploring a wide range of feasible compliance 

options, did the Company determine that retirement and decertification of these units is in the 

best interest of customers. And though the MATS rule and other existing and pending 

environmental regulations are the key drivers, the current forecasts of natural gas prices and the 

recent economic downturn and resulting loss of load have also had a negative impact on the 

economics of these units. While these units have provided significant benefit to customers for 

decades, the economic analysis now shows that retirement is in the best interest of customers. 

In the case of Plant Branch Units 3 and 4, major capital investment would be required to achieve 

MATS and Georgia Multipollutant Rule compliance. To put the magnitude of these costs into 

perspective, the total combined cost of MATS compliance for all the units the Company plans to 

control or fuel switch is roughly equal to the cost of bringing Plant Branch Units 3 and 4 alone 

into MATS compliance. Aside from the negative economic results of the Plant Branch Units 3 

and 4 retirement analysis, such significant up front capital investment would put immediate 

upward pressure on rates with only a modest chance of long-term economic benefit to customers. 

As further detailed in Section 1.5.2, the Company also requests an amendment to the 

decertification date for Plant Branch Unit 1 specified in the Commission’s final order in Docket 

No. 34218. This adjustment will provide the most cost effective method to ensure reliable 
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startup of Plant Branch Units 3 and 4 until their retirement and allow Unit 1 to continue to 

provide energy benefits to customers until 2015.

In the case of Plant Kraft Units 1-4, the most feasible MATS compliance option—future 

operation on oil—does not offer any economic benefit to customers in any of the analysis 

scenarios. Similarly, in the case of Plant Yates Units 1-5, switching to natural gas as the primary 

fuel because of the MATS requirements would not offer any economic benefit to customers. 

And although Plant McManus Unit 1 and 2 would not need additional controls to become MATS 

compliant, the MATS rule does contain requirements which limit an oil-fired plant’s capacity 

factor. 

In addition to the decertification of Plant Branch Units 3 and 4, Plant McManus Units 1 and 2, 

Plant Kraft Units 1-4, and Plant Yates Units 1-5, the Company also seeks decertification for 

Plant Boulevard Units 2 and 3 and Plant Bowen Unit 6. Similar to Plant Mitchell Unit 4C, which 

was decertified in 2012 as a result of the need for significant repairs, Plant Boulevard Units 2 and 

3, each 14 MW combustion turbines (“CTs”), recently experienced compressor failures that 

caused substantial damage. While an economic evaluation of the units results in a positive NPV 

for customers over a 30-year study period, similar to Mitchell 4C, the Company has requested 

decertification of the units in light of the age of the units, the possibility of additional reliability 

issues and costs in the future, the extensive nature of the repairs required, and the possibility of 

more extensive damage found once the units were opened for more detailed inspection. 

The Company has also determined that it will be economically beneficial for customers to retire 

Plant Bowen Unit 6. Plant Bowen Unit 6 is a 32 MW oil-fired combustion turbine that is only 

permitted to operate during non-summer months due to ozone nonattainment requirements in the 

area. Furthermore, removal of the unit as quickly as possible will allow more flexibility for the 

installation of baghouses on Plant Bowen Units 3 and 4 given certain logistical constraints of the 

site. When the benefits of retiring the unit became apparent, the Company proactively sought 

sale opportunities for the generator and was able to reach an agreement to sell the unit, pending 

Commission approval of the decertification, that is in the best interest of customers. The 

Company requests that the Commission grant this decertification by April 16, 2013 to take 

advantage of the sale agreement. Expedited Commission approval of the decertification of the 
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unit will allow the buyer sufficient time to remove the unit before June 1, 2013, which would 

ensure that the unit does not impede construction of the baghouses for Plant Bowen Units 3 and 

4.

In summary and as specified in the Company’s Application for Decertification (“2013 

Decertification Application”), the plants for which the Company seeks decertification are Plant 

Branch Units 3 and 4, Plant McManus Units 1 and 2, Plant Kraft Units 1-4, Plant Yates Units 1-

5, Plant Boulevard Units 2 and 3, and Plant Bowen Unit 6, which brings the Company’s 

decertification requests in this filing to a total of 2,093 MW of generating capacity. The slate of 

generating unit retirements recommended in this case is unprecedented in the history of Georgia 

Power but, unfortunately, is necessitated by the stringent and costly requirements of the MATS 

rule and other environmental rules, as well as other economic considerations. It is important to 

note that Georgia Power is not alone in facing the need to retire substantial amounts of coal- and 

oil-fired generation. Numerous utilities across the country and their respective state regulatory 

commissions have made or are facing similar difficult decisions with respect to the future of 

coal- and oil-fired generating units. 

The Company assesses the feasibility of repurposing sites where units have been retired and 

decommissioned. Future uses of these sites may include development of new generation 

resources similar to the new combined cycle (“CC”) units at Plant McDonough-Atkinson. If the 

site is not suitable for future generation development or for other utility use, the Company may 

choose to sell the site. In some cases, sales may allow for other land uses facilitating economic 

development similar to Plant Riverside in Savannah. In any event, the Company will evaluate 

the best future use of the property taking into account stakeholder interests and value to 

customers. The Company’s long term planning process also includes identifying, assessing, and 

acquiring (if needed) sites that are suitable for future generation development. Relevant factors 

for such assessments may include proximity to electric transmission networks, natural gas 

pipelines, sources of cooling water, railroads, size of the property and availability of contiguous 

parcels. 

The Integrated Resource Plan presented in this filing maintains an efficient and diverse fleet of 

supply-side resources coupled with demand side resources. The Company is in the midst of a 
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significant transition in its fleet that will result in a more diverse fuel portfolio and ensure that 

Georgia Power is able to continue to provide its customers with reliable and affordable electricity 

while helping to mitigate the risk of fuel price volatility. This period of transition will also result 

in a younger, more efficient fleet and one with fewer coal resources, which may lessen 

customers’ exposure to the cost of potential carbon regulation or legislation. Additionally, by 

further controlling the Company’s largest and most efficient coal units (units in which the 

Company has already invested significant capital costs for environmental controls), the Company 

retains the significant energy benefits of these units while also positioning itself to be able to 

respond to future increases or volatility in the cost of natural gas. And by moving forward with 

switching primary fuels at Plant McIntosh Unit 1, Plant Yates Units 6 and 7 and Plant Gaston 

Units 1-4, the Company is able to retain the operational and economic benefits of these units for 

customers. Finally, by deferring a final decision regarding the conversion of Plant Mitchell Unit 

3, the Company maintains the option of cost-effectively converting an existing unit to a 

renewable biomass generating unit in its future resource plans. 

The planning process mandated under the IRP Act and overseen by the Commission has resulted 

in a fleet of supply-side resources that will continue to deliver value to customers for generations 

to come. The comprehensive and detailed nature of this process ensures that benefits to 

customers are maximized. For example, the three new Plant McDonough-Atkinson CC units 

that were identified through the IRP process and constructed under the supervision of the 

Commission’s construction monitoring protocols are now providing highly efficient natural gas 

generation, capitalizing on the current low natural gas prices and reducing customers’ fuel costs 

(as demonstrated by the Company’s recent fuel rate decreases). The construction of the new 

McDonough-Atkinson units also eliminated the need for significant transmission upgrades that 

otherwise would have been necessary, further highlighting the benefits of the IRP process. 

Likewise, the IRP process also identified the value of adding the new Plant Vogtle units, which 

will bring needed base load capacity and even greater fuel diversity and energy benefits to the 

Company’s fleet.

The Company also continues its pursuit, in collaboration with the Commission, of cost-effective 

renewable resources. With over 1,088 MW of hydro generation, over 62 MW of solar generation 

(in service or under contract today), and 142 MW of biomass generation, the Company has 
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demonstrated a firm commitment to identifying all cost-effective renewable resources for the 

benefit of customers. In total, the Company expects to have more than 1,500 MW of renewable 

generation available to serve customers by the end of 2016. 

The Georgia Power Advanced Solar Initiative (“GPASI”) is the most recent and most 

noteworthy step the Company has taken to obtain an increasing amount of solar resources as 

declining technology prices have made such resources less costly. The GPASI builds on the 

solar resources already obtained by the Company through the Large Scale Solar (“LSS”) 

program and the Green Energy Program. After all resources are obtained through the GPASI, 

the Company expects to have 270 MW of solar capacity under contract in Georgia, putting it 

among the top U.S. utilities operating in states without a renewable portfolio standard. The 

Company also continues to engage in R&D efforts to gain more insight into the potential for 

further utilization of solar resources in Georgia. 

Additionally, the Company continues to evaluate the economic benefit to customers of the Plant 

Mitchell Unit 3 biomass conversion. As detailed further in this filing, a decision concerning the 

conversion of Plant Mitchell Unit 3 is being deferred at this time. The Company is currently 

conducting a thorough evaluation of the impacts of the final EPA Industrial Boiler Maximum 

Achievable Control Technology standard (“IB MACT”) that was released in late December. In 

this 2013 IRP, Plant Mitchell Unit 3 is currently assumed to be unavailable in 2015 and 2016 and 

then available as a biomass generating unit in 2017. 

The Company also continues its disciplined pursuit of cost-effective Demand Side Management 

(“DSM”) programs through its collaboration with Commission Staff and the Demand Side 

Management Working Group. The specific certification and amendment requests of the 

Company have been made concurrently with this filing in the Application for the Certification of 

its Amended Demand Side Management Plan in Docket No. 36499 (“2013 DSM Application”). 

Specifically, in its 2013 DSM Application, the Company requests certification of one new 

commercial program, amendment of three currently certified programs, decertification of one 

program (though the program activities will be subsumed by an existing program), and approval 

of updated program budgets for the remaining programs previously certified in Docket No. 

31082. The Company’s current DSM portfolio consists of demand response programs, energy 
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efficiency programs, pricing tariffs, and other activities. The Company projects that by 2016 

these programs will reduce peak demand by approximately 2,000 MW. 

The 2013 IRP presented in this filing is robust and capable of sustaining long term reliability in a 

cost-effective manner through a diverse portfolio of resources. The IRP planning process 

overseen by the Commission has created a versatile fleet that can respond effectively to swings 

in gas and coal prices, with new nuclear providing low cost energy and greater fuel cost stability 

than fossil fuels. With the Commission’s oversight, the Company has developed a cost-effective 

and balanced MATS compliance strategy for the benefit of customers and is also well positioned 

for compliance with future environmental requirements. The plan also maintains and enhances 

the Company’s current DSM programs. In addition, the Company is well-positioned for the 

return of customer load growth given Georgia’s positive long-term economic prospects as a 

destination state with a business friendly environment. By 2020, the state of Georgia is projected 

to add one million new residents, and the ability to have in place the necessary energy 

infrastructure for such growth is a direct result of the collaborative planning process facilitated 

by the IRP Act and guided by the Commission. This process has allowed the Company and the 

Commission to maintain a reasoned and disciplined approach to meeting customer demand while 

effectively responding to a changing regulatory environment in a way that would not have been 

achievable through other more narrowly focused approaches, all while maintaining rates below 

the national average. 

In summary, the Company seeks approval of:

1) Its 2013 Integrated Resource Plan and the associated Action Plan;

2) Decertification of Plant Branch Units 3 and 4, Plant Yates Units 1-5, and Plant McManus 

Units 1 and 2 effective by the MATS compliance date of April 16, 2015, decertification 

of Plant Kraft Units 1-4 one year past the MATS compliance date (by April 16, 2016), 

decertification of Plant Boulevard Units 2 and 3 effective as of the date of the final order 

in this proceeding, and approval of expedited decertification of Plant Bowen Unit 6 by 

April 16, 2013 as specified in the 2013 Decertification Application;

3) A switch to natural gas as the primary fuel for Plant Yates Units 6 and 7 and Plant Gaston 

Units 1-4; 
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4) An amendment of the decertification date specified in the Commission’s final order in 

Docket No. 34218 for Plant Branch Unit 1 from December 31, 2013 to coincide with the 

decertification of Plant Branch Units 3 and 4; 

5) A certificate of public convenience and necessity for one new DSM program, a certificate 

amendment for three previously certified programs, decertification of one DSM program, 

and approval of updated program economics for all other previously certified energy 

efficiency DSM programs as further specified in the 2013 DSM Application in Docket 

No. 36499;

6) Reclassification of the remaining net book values of Plant Branch Units 3 and 4 and Plant 

Boulevard Units 2 and 3 as of their respective retirement dates to regulatory asset 

accounts and the amortization of such regulatory asset accounts ratably over a period 

equal to the respective unit’s remaining useful life approved in Docket No. 31958;

7) In the event the Commission does not approve the expedited decertification of Plant 

Bowen Unit 6, reclassification of the remaining net book value of Plant Bowen Unit 6 as 

of its respective retirement date to a regulatory asset account and the amortization of such 

regulatory asset account ratably over a period equal to the unit’s remaining useful life 

approved in Docket No. 31958;

8) Amortization of approximately $38 million of Plant Branch Units 3 and 4 and 

approximately $14 million of Plant Yates Units 6 and 7 environmental construction work 

in progress (“CWIP”) (which has been reclassified as a regulatory asset in accordance 

with the Commission’s Order in Docket No. 31958) ratably over a three year period 

beginning January 2014; 

9) Reclassification of any unusable material and supplies (“M&S”) inventory balance 

remaining at the unit retirement dates to a regulatory asset as identified in accordance 

with the Commission’s Order in Docket No. 31958 for recovery over a period to be 

determined by the Commission in the Company’s next base rate case following the unit 

retirements;

10) The capital costs the Company will incur for a portfolio of certain renewable 

demonstration projects (but not yet the recovery of such costs), as set out in the Selected 

Supporting Information section of Technical Appendix Volume 2; and
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11) The capital and operations and maintenance (“O&M”) costs (but not yet the recovery) of 

measures taken to comply with existing government-imposed environmental mandates, as 

set out in the Selected Supporting Information section of Technical Appendix Volume 2.

1.2 INTRODUCTION

Georgia Power, a subsidiary of Southern Company, is an investor-owned electric utility serving 

customers in 57,000 of the state’s 59,000 square miles. The Company serves approximately 2.4 

million retail customers in all but four of Georgia’s 159 counties.

Southern Company is the parent of Georgia Power, Alabama Power Company (“Alabama 

Power”), Gulf Power Company (“Gulf Power”), Mississippi Power Company (“Mississippi 

Power”), and Southern Power Company (“Southern Power”), (collectively, the “Operating 

Companies”), as well as certain service and special-purpose subsidiaries. The Operating 

Companies, together also referred to as the Southern Electric System (“System”), coordinate 

system operations and jointly dispatch their generating units to capture the economies available 

from power pooling. The System is a member of the Southeastern Electric Reliability Council 

(“SERC”), a group of electric utilities (and other electric-related utilities) coordinating operations 

and other measures to maintain a high level of reliability for the electrical system in the 

southeastern United States. The four traditional retail operating companies, Georgia Power, 

Alabama Power, Gulf Power, and Mississippi Power, also participate in coordinated generation 

and transmission planning as appropriate.

Georgia Power’s common stock is held by Southern Company, which had 149,628 shareholders 

of record at year end 2012. 

Georgia Power has 149 company-owned generating units (36 fossil steam, 71 hydroelectric, 4 

nuclear, 5 CCs, and 33 CTs, excluding 4 CTs which are not permitted for normal summer 

operation) that provide approximately 17,400 MW of retail peak season generating capacity. Of 

the energy from Company-owned units for the first eleven months of 2012, 42 percent is from 

coal, 18 percent from nuclear, 4 percent from hydroelectric, and 36 percent from natural gas and 

oil.
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1.3 THE 2010 IRP

In January 2010, Georgia Power filed its seventh IRP. The 2010 IRP was designed to meet the 

energy needs of the Company’s customers using a mix of supply-side and demand-side 

resources. The Commission approved the IRP developed by Georgia Power with modifications 

as specified in its order dated July 13, 2010 (the “2010 IRP Order”).

In response to the Commission’s 2010 IRP Order, the Company took the following actions: 

1) Updated the cost of Expected Unserved Energy (“EUE”);

2) Continued to pursue a cost-effective conversion of Plant Mitchell Unit 3 to 100 percent 

biomass (Docket No. 28158) by completing a study of a direct injection technology 

which may lead to lower capital cost and higher net capacity compared to other biomass 

conversion options;

3) Responded to the Commission’s Order requiring certain actions in regard to DSM 

programs and planning activities;

4) Filed the Achievable Energy-Efficiency Potentials Assessment in January 2012 in 

response to the Commission’s order for a new energy efficiency potential study; 

5) Filed complete Process and Impact Evaluation result reports in December 2012 for the 

seven energy efficiency programs certified in the 2010 DSM certification proceeding; 

and

6) Complied with the Nine Step DSM planning process for development of the Company’s 

2013 IRP DSM plan. 

1.4 SIGNIFICANT RECENT DEVELOPMENTS 

As discussed in Section 1.1, the need to file the Company’s 2011 IRP Update and application 

was driven largely by the significant amount of uncertainty created by numerous new 

environmental regulations under development by the EPA. The most significant of these 

regulations, with the most immediate effect, was the EPA’s MATS rule. As a result, the 

Company recommended, and the Commission approved, numerous actions that sought to 

mitigate the impact of these environmental rules and minimize costs for customers. These 

included:
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 Initial work necessary on seven baghouses to strive to meet the MATS compliance 

deadline for the affected units at Plants Bowen, Hammond, and Wansley. 

 Decertification of Plant Branch Units 1 and 2 effective on the Georgia Multipollutant 

Rule compliance dates of December 31, 2013 and October 1, 2013, respectively, and 

Plant Mitchell Unit 4C effective as of the date of the Commission’s final order on March 

26, 2012.

 Certification of the following three PPAs with Southern Power Company from natural 

gas-fired facilities—Harris (625 MW), West Georgia (298 MW) and Dahlberg (75 MW). 

The Dahlberg and West Georgia agreements commence January 1, 2015, and the Harris 

agreement commences June 1, 2015. All three PPAs end on May 31, 2030. 

As described further in Section 1.5 and Section 6, the Company has continued its analysis of the 

final MATS rule and in this filing has proposed for the Commission’s consideration a final 

MATS compliance plan. Additional significant developments since the Company’s 2010 IRP 

are described below. 

1.4.1 Georgia Power Advanced Solar Initiative

On September 26, 2012, the Company filed the GPASI in Docket No. 36325 and the 

Commission approved the program on November 29, 2012. Under the GPASI, the Company 

will contract for up to 210 MW of solar energy through both distributed and utility scale projects 

by the end of 2014. Georgia Power expects to purchase up to 120 MW of utility scale solar 

generation through competitive RFPs. Distributed solar energy will be procured by Georgia 

Power through the purchase of 90 MW of energy from small and medium-scale solar projects 

owned by customers and developers. More details regarding the GPASI are contained in Section 

10. 

1.4.2 Plant McDonough-Atkinson Units 4-6

The Commission approved, in Docket No. 24506, the Company’s Application for Decertification 

of Plant McDonough-Atkinson Units 1 and 2 and Certification of Plant McDonough-Atkinson 

Units 4-6. The natural gas fired CC Units 4-6 are now in commercial operation, providing 

benefits to customers as some of the most efficient units in Georgia Power’s fleet. Unit 6, the 
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last unit to be placed in-service, achieved commercial operation on October 28, 2012. 

Additionally, decommissioning activities for the coal-fired Plant McDonough-Atkinson Units 1 

and 2 are currently underway. Unit 1, the last operational coal-fired generating unit at Plant 

McDonough-Atkinson, was retired on February 29, 2012.

1.4.3 Plant Vogtle Units 3 and 4

As approved in Docket No. 27800, Georgia Power and its partners—Oglethorpe Power, MEAG 

Power, and Dalton Utilities—are adding two nuclear units at Plant Vogtle to meet customers’ 

growing needs and provide important fuel diversity and fuel savings benefits. Addition of the 

units represents a $14 billion capital investment in Georgia and is the largest job-producing 

project in the state, employing approximately 5,000 people during peak construction and creating 

800 permanent jobs when the units begin operating. Several milestones have been accomplished 

and highlights include:

 First combined operating licenses issued by the Nuclear Regulatory Commission 

(“NRC”); 

 10 million project work hours achieved; and 

 Initial Institute of Nuclear Power Operations accreditation of the Plant Vogtle Units 3 

and 4 operations training programs. 

1.4.4 Wholesale to Retail Actions

On July 27, 2009, the Commission accepted for retail service the Blocks 5 and 6 offer of 178 

MW of oil-fired peaking capacity that will become available to retail at different times as the 

existing wholesale contracts expire, with the total capacity in retail rate base on January 1, 2016. 

The Commission certified Blocks 5 and 6 on March 5, 2010. On October 10, 2012, the 

Commission accepted for retail service 250 MW of Block 1 coal-fired capacity that will become 

available to retail on April 1, 2016 and 312 MW of Blocks 2-4 coal-fired capacity that will 

become available to retail on January 15, 2015. The blocks were certified on March 26, 2012. 

More details regarding Wholesale to Retail actions are contained in Section 12. 

1.4.5 Reduced Fuel Rates

Since the 2010 IRP, the Company’s fuel rates have been reduced on three separate occasions, 

largely as a result of lower natural gas prices. The addition of the three McDonough-Atkinson
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CC units has allowed customers to benefit even more from such prices. The average nonseasonal fuel rates have decreased 24.5% from FCR-21 to FCR-23.

1.4.6 DSM Program Implementation

The Company implemented the seven DSM programs that were certified in the 2010 IRP with a 

ramp up during the first three years. As part of the program implementation, the Company hired 

implementation contractors, set up implementation protocols, hired a program evaluation 

contractor and completed full program evaluations for the seven energy efficiency programs. In 

2011, Georgia Power achieved 130.4 gigawatt hours (“GWh”) of gross energy savings as 

compared to an energy savings target of 104.1 GWh. In 2012, the energy savings target was 

203.3 GWh and the Company is likely to achieve about 215 GWh of gross energy savings (final 

amount has not been determined as of filing). More details regarding the Company’s DSM 

programs are contained in Section 5 and the 2013 DSM Application. 

1.5 THE SUPPLY-SIDE PLAN

Georgia Power’s current supply-side plan, as set forth in the 2011 IRP Update and as further 

supplemented herein, is sufficient to provide cost-effective and reliable sources of capacity and 

energy through 2015 and beyond. More details regarding the Company’s supply-side plan are

contained in Section 6 and the formal decertification requests are included in the 2013 

Decertification Application. 

1.5.1 MATS Compliance Strategy Update

As discussed in Section 1.1, the MATS rule is a key driver of the Company’s requests in this 

proceeding. Released on March 3, 2011, the proposed version of the EPA’s MATS rule 

(formerly referred to as the “Utility MACT” rule) included stringent emissions limits on coal and 

oil-fired electric utility steam generating units for acid gases, mercury, and total particulate 

matter, and included an impracticable compliance deadline. In response to the proposed MATS 

rule, the Company developed compliance strategies and recommendations that were included in 

the 2011 IRP Update filed in August 2011. While the 2011 IRP Update proceedings were 

pending before the Commission, the EPA released its final MATS rule on December 21, 2011, a 
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mere eight days prior to the filing of the Company’s rebuttal testimony and amended application. 

Given the timing of the rule’s release, it was impractical from a technical perspective for the 

Company to complete a full review of the final rule, including changes from the proposed rule, in 

order to analyze its impact on the Company’s coal- and oil-fired plants on a unit-by-unit basis. 

Therefore, the Company continued to recommend and the Commission approved expenditures 

associated with the initiation of construction of baghouses for Plant Bowen Units 1–4, Plant 

Wansley Units 1 and 2, and Plant Hammond Units 1–4. The Company was ordered to keep the 

Commission apprised of its evaluation through monthly reports filed at the Commission. 

Since that time, Georgia Power has continued an evaluation of the requirements of the final 

MATS rule and the overall compliance strategy on a unit-by-unit basis for the ten generating 

units at Plant Bowen Units 1–4, Plant Wansley Units 1 and 2 and Plant Hammond Units 1–4. As 

a result of its analysis, the Company determined, and has previously notified the Commission in 

Docket No. 34218, that only Plant Bowen Units 3 and 4 would need baghouses at this time and 

that MATS compliance can be achieved at Plant Bowen Units 1 and 2, Plant Wansley Units 1 

and 2 and Plant Hammond Units 1–4 by installing activated carbon and hydrated lime injection 

systems and performing precipitator work (an activated carbon and hydrated lime injection 

system will also be required at Plant Bowen Units 3 and 4 in addition to the baghouses). All 

units at Bowen, Hammond and Wansley will install scrubber additive systems and evaluate other 

projects needed to enhance the availability and reliability of existing scrubbers after the MATS 

compliance deadline. 

The final MATS rule contained differences from the proposed rule that allowed the Company to 

remove five baghouses from its compliance strategy. Chief among these differences was a 

change in the particulate matter standard between the proposed and final rules. In the proposed 

rule, the EPA would have imposed a very stringent and complicated limit on particulate 

emissions that ultimately would have resulted in a unit-specific limit on particulate matter 

emissions, thereby removing all compliance margin without accounting for natural variation in 

the operation of a generating unit. Therefore, the only option for compliance under the proposed 

rule would have been installation of baghouses to attempt to comply under all operating 

conditions. In the final rule, however, the EPA altered the form of the particulate matter limit 

such that, while still very stringent, it is a standard limit across all units instead of a unit-specific 
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limit. The limit also is in a form that allows for additional compliance options to be considered 

and evaluated on a unit-specific basis as is further explained in the Environmental Compliance 

Strategy (“ECS”) document in Technical Appendix Volume 2. 

Aside from Plant Bowen Units 1–4, Plant Wansley Units 1 and 2, and Plant Hammond Units 1–4 

and the coal-fired units for which the Company seeks decertification, additional environmental 

controls will be required for the remaining coal-fired units to operate on coal after the MATS 

compliance date of April 16, 2015. Specifically, Georgia Power plans to utilize a bromine

additive at Plant Scherer and switch Plant McIntosh 1 to operate on lower-priced Powder River 

Basin coal (pending a successful test burn and further study). These actions will ensure coalfired generation remains a cost-effective and reliable part of the fleet, maintaining essential fuel 

diversity. 

Finally, for the remaining coal-fired units that will continue to operate, the Company has 

concluded that it is not cost-effective to install the environmental controls necessary to enable 

these units to remain operational on coal. Instead, the Company has found it to be most costeffective for customers to switch Plant Yates Units 6 and 7 and Plant Gaston Units 1–4 to natural 

gas as the primary fuel, with coal used as a backup fuel. 

For additional information regarding the development of the Company’s MATS compliance 

strategy, please see the ECS document included in Technical Appendix Volume 2. 

1.5.2 Unit Retirements

As described in Section 1.1, the Company’s evaluation of the MATS rule has also led to the 

conclusion that the most cost-effective compliance option for certain of the Company’s coal- and 

oil-fired units is retirement. The units for which the Company has made such a determination 

and seeks decertification in the 2013 Decertification Application are Plant Branch Units 3 and 4, 

Plant Kraft Units 1-4, Plant McManus Units 1 and 2, and Plant Yates Unit 1-5. These difficult 

decisions are driven by unfavorable economics, primarily resulting from the scope and cost of 

environmental controls and limitations required for MATS compliance. In addition, for the 

reasons stated in Section 1.1, the Company is requesting decertification of Plant Boulevard Units 
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2 and 3 effective as of the date of the final order in this proceeding and expedited decertification 

of Plant Bowen Unit 6 by April 16, 2013. 

The decision to decertify Plant Branch Units 3 and 4 presented additional challenges that 

required consideration. Units 3 and 4 are coal-fired supercritical generating units capable of an 

output of 1,016 MW. Supercritical steam units require a source of steam to assist with the 

startup of the unit. As the decision to retire Units 3 and 4 became evident, the Company 

determined that utilizing Plant Branch Unit 1 to provide a source of startup steam for Units 3 and 

4 would be more cost effective than purchasing and installing an auxiliary boiler on the site for 

the short period until these units are decertified. However, as currently drafted, the Georgia 

Multipollutant rule requires installation of SCR and scrubber on Unit 1 by December 31, 2013, 

the current Commission-approved decertification date. To allow for a short-term extension of 

the Unit 1 Multipollutant rule compliance date to allow Unit 1 to provide startup steam for Units 

3 and 4, the Georgia Environmental Protection Division (“EPD”) has begun a process to revise 

the rule. The revision of the rule is intended to align the Multipollutant Rule compliance date for 

Unit 1 with the date required in the MATS rule, April 16, 2015. As part of this rule revision, the 

EPD will accelerate the requirement to install controls on Units 3 and 4 from the end of 2015 to 

April 16, 2015, aligning the compliance dates for those units with the MATS rule as well. 

Therefore, the Company is requesting an amendment to the decertification date specified in the 

Commission’s final order in Docket No. 34218 for Plant Branch Unit 1 from December 31, 2013 

to coincide with the decertification of Plant Branch Units 3 and 4 by April 16, 2015. This 

change, if approved by the Commission and the EPD, will provide the most cost effective 

method to ensure reliable startup of Plant Branch Units 3 and 4 until their retirement. 

Additionally, although the long-term decision is to retire Plant Kraft Units 1-4, a one year MATS 

extension will be requested from the EPD to ensure reliability while necessary transmission 

improvements in the area are completed. 

Table 1.5 summarizes the Company’s supply-side plan: 
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Table 1.5

Installation of Environmental Controls for MATS Compliance

Plant Bowen Units 3 and 4 Baghouses along with Activated Carbon and Hydrated Lime 

Injection systems

Plant Bowen Units 1 and 2 Activated Carbon and Hydrated Lime Injection systems

Plant Wansley Units 1 and 2 Activated Carbon and Hydrated Lime Injection systems

Plant Scherer Units 1-3 Bromine Injection system

Plant Hammond Units 1-4 Activated Carbon and Hydrated Lime Injection systems

Switching Primary Fuels for MATS Compliance

Plant Yates Units 6 and 7 Coal to Natural Gas

Plant McIntosh Unit 1 Bituminous Coal to PRB Coal; Activated Carbon and Dry 

Sorbent Injection systems

Plant Gaston Units 1-4 Coal to Natural Gas

Biomass Conversion

Plant Mitchell Unit 3 Coal to Biomass

Requested Decertifications and Applicable Dates

Plant Branch Units 3 and 4 By the MATS compliance date of April 16, 2015 

Plant Yates Units 1-5 By the MATS compliance date of April 16, 2015

Plant McManus Units 1 and 2 By the MATS compliance date of April 16, 2015

Plant Kraft Units 1-4 1 year past the MATS compliance date (by April 16, 2016)

Plant Boulevard Units 2 and 3 Date of the final order in this proceeding

Plant Bowen Unit 6 By April 16, 2013

The Selected Supporting Information section of Technical Appendix Volume 2 includes certain 

costs the Company will incur to implement a portfolio of renewable demonstration projects. 

Sections 10.3.3, 10.3.4, 10.3.6, and 10.6.1 of the Main Document of the IRP contain descriptions 
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of these projects. The Company believes that it is appropriate to review and approve these costs 

in the overall context of this IRP proceeding. 

1.6 THE DEMAND-SIDE PLAN

The Company’s current DSM portfolio consists of demand response programs, energy efficiency 

programs, pricing tariffs, and other activities. The Company projects that by 2016 these 

programs will reduce peak demand by approximately 2,000 MW. This load reduction represents 

more than 12 percent of the Company’s current load.

In accordance with the final order in the 2010 IRP, the Company has continued to work closely 

with the DSM Working Group through the use of the Nine Step process for DSM program 

development. The Company prepared an updated energy efficiency technology catalog, 

completed and filed an energy efficiency potential study, and conducted a comprehensive 

analysis of potential DSM programs with the assistance and input of the DSM Working Group. 

The recommended DSM action plan includes seeking Commission approval for a certificate for 

one new DSM program, amending the certificate of three currently certified DSM programs, 

decertifying one DSM program (though the program activities will be subsumed by an existing 

program) and updated program economics for the remaining certified DSM programs in the 

Company’s 2013 DSM Application. The Company also intends to continue the Power Credit 

residential program, which was previously certified in Docket No. 6315. 

However, the Company notes that avoided cost savings are lower, which has had a significant 

and negative impact on the economics of the Company’s current and proposed DSM programs. 

As discussed in Section 5, Total Resource Cost (“TRC”) Test results declined and Ratepayer 

Impact Measure (“RIM”) Test results worsened, causing concerns for the Company in its efforts 

to balance the economic benefits these programs provide for participating customers with the 

rate impacts to all customers within a given class caused by the programs. Nevertheless, the 

Company supports the continuation of the energy efficiency programs approved in the 2010 

DSM Certification filing and also seeks to certify a Small Business program targeted toward a 

hard to reach customer sector. The Company plans to continue to monitor program costs and 
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economics during 2014 - 2016 and will be prepared to modify programs in the future if the 

significant upward pressure on rates continues.

Summary information for two alternative DSM sensitivity cases is also included in this filing. 

One alternative sensitivity case, deemed the “Advocacy Sensitivity Case,” presents a potential 

set of DSM programs designed around the recommendations from some members of the DSM 

Working Group to achieve 10 year cumulative energy savings of 9.5 percent. The other 

alternative sensitivity case represents the “Aggressive Sensitivity Case” that was outlined in the 

Nine Step process. 

1.7 THE PRICING PLAN

The Company will continue its strategy of developing and promoting rates that give customers 

pricing signals that encourage peak demand reduction and load shifting. Innovative programs 

developed by Georgia Power (such as our Real Time Pricing (“RTP”) program, Demand Plus 

Energy Credit (“DPEC”) and Time of Use (“TOU”) rates) have been effective in reducing the 

peak demand for electricity. 

Georgia Power completed installation of the Advanced Metering Infrastructure (“AMI”) “smart” 

meters in 2012. The Company leverages the AMI investment by promoting rates that send 

strong, clear pricing signals such as the Time of Use-Residential Energy Only (“TOU-REO”) 

and Time of Use Plug-in Electric Vehicle (“TOU-PEV”) rates. The Company’s promotions will 

continue to focus on helping customers save money and energy by reducing usage or shifting 

loads from the on-peak time period. 

Georgia Power also offers the Time of Use-Fuel Cost Recovery (“TOU-FCR”) rider. TOU-FCR 

was made permanent and expanded in 2012, and is now available on a voluntary basis to all 

customers on TOU base tariffs. Additionally, the Time of Use-Fuel Cost Recovery Three Part 

(“TOU-FCR-TP”) pilot rate was introduced in 2012. The TOU-FCR-TP pilot rate is available to 

customers on the TOU-PEV and Time of Use-Medium Business (“TOU-MB”) rates. TOU-FCR 

rates will further strengthen price signals seen by customers on time of use rates. 
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1.8 THE ENVIRONMENTAL PLAN

The ECS document included in Technical Appendix Volume 2 reflects the most recent 

regulatory developments and related strategies to ensure that the Company’s operations continue 

to meet all local, state and federal environmental laws and regulations. The ECS establishes a 

general direction for compliance and allows for individual decisions to be made based upon 

specific information available at the time. This approach is necessary to maintain the flexibility 

to match a rapidly changing regulatory compliance environment. In the 2011 IRP Update, the 

ECS contained a strategy based heavily on the most impactful environmental rule that had been 

proposed at that time, the EPA’s MATS rule. The ECS in the current filing has been updated to 

reflect the Company’s compliance strategy for the final MATS rule and other existing and 

expected environmental requirements. 

The Company anticipates that it will seek, and the Commission may approve, a modified form of 

the current ECCR tariff in the 2013 base rate case. Therefore, the Company believes the related 

environmental costs to be proposed for recovery through the ECCR tariff should be reviewed and 

considered in the overall context of this IRP. The costs which the Company seeks to have 

approved are more specifically described in the Selected Supporting Information section of 

Technical Appendix Volume 2. These costs are generally capital and O&M costs necessitated 

by federal and state environmental laws and regulations. 

1.9 RELIABILITY

Over the next several years, Georgia Power has sufficient resources to maintain an adequate 

planning reserve margin given anticipated demand of its customers and the current regulations 

impacting electric generating units. Given the uncertain nature of forecasts and of future 

regulations, the Company will continue to constantly evaluate its resource needs and will 

respond as necessary to ensure the reliability and economics of the Georgia Power system. 

Georgia Power and the System maintain adequate reserve margins in their respective plans to 

ensure reliable and cost-effective service to their customers. 
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1.10 RESERVE MARGINS

After an analysis of load forecast and weather uncertainty, the cost of expected unserved energy, 

as well as the current and near-term projected generation reliability of the System, the Company 

will maintain a target system planning reserve margin of 15 percent in the long term, which is 

very near the minimum total cost but carries less risk than the absolute minimum cost point. As 

demonstrated in the Reserve Margin Study included in Technical Appendix Volume 1, the 

absolute minimum cost point rose slightly because of updates to certain key assumptions shown 

in the bullet points below, although not enough to justify any change to the target reserve margin. 

For the short-term horizon, the Company will maintain a 13.5 percent system planning reserve 

margin guideline, but may periodically review the availability and cost of resources in the market 

and adjust short-term resource procurement decisions accordingly.

The updates to certain key assumptions that affected the results of this Reserve Margin Study are 

as follows:

 The economic carrying cost of a CT in 2012 dollars decreased by less than 5 percent. A 

lower CT cost results in a higher reserve margin for the minimum cost point. 

 The Southern Electric System average peak equivalent forced outage rate (“EFOR”) has 

increased slightly since 2009. Higher EFOR results in more projected reliability 

purchases and more EUE, which results in a slightly higher reserve margin for the 

minimum cost point.

 An outage cost survey of Georgia Power and Mississippi Power customers was 

completed in 2011 by Freeman Sullivan & Company in accordance with the 

Commission’s 2010 IRP Order. The cost of EUE from this survey is substantially higher 

than in previous studies. Since EUE is so infrequent, even at lower reserve margins, this 

change only slightly increased the reserve margin for the minimum cost point. For 

results of the study, see the EUE Study in Technical Appendix Volume 1. 

1.11 THE DEMAND AND ENERGY FORECASTS

A twenty-year forecast of energy sales and peak demand was developed to meet the planning 

needs of Georgia Power. The Budget 2013 Load and Energy Forecast (“Budget 2013 Forecast”) 
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includes the retail classes of residential, commercial, industrial, MARTA, and governmental 

lighting. Effective January 1, 2013, Georgia Power is no longer serving the city of Hampton 

wholesale requirements load. 

The peak demand forecast for the Budget 2013 Forecast has been adjusted to account for the 

effects of RTP customers’ response, expected cogeneration, and residential and commercial 

demand side management programs. 

A detailed discussion of the revised territorial energy and demand forecasts is set forth in the 

Budget 2013 Forecast in Technical Appendix Volume 2.

1.12 TRANSMISSION PLAN

This IRP includes the Company’s ten-year transmission plan, which identifies the transmission 

improvements needed (based upon current planning assumptions) to maintain a strong and 

reliable transmission system. The development of this plan is conducted in accordance with the 

System transmission planning guidelines and with North American Electric Reliability Council 

(“NERC”) planning standards. Along with the ten-year plan, Georgia Power has included a 

comprehensive and detailed bulk transmission plan of the Georgia Integrated Transmission 

System as required by the amended rules adopted by the Commission in Docket No. 25981. 

Additional transmission information is also available as required by Docket No. 31081. 

1.13 INTEGRATED RESOURCE PLAN 

The Company’s 2013 IRP reflects the following:

 Purchase of 998 MW of capacity and energy certified by the Commission in Docket No. 

34218 on March 26, 2012, with 373 MW available beginning January 1, 2015 and the 

remaining 625 MW available beginning June 1, 2015;

 Retirement of Plant Branch Units 3 and 4, Plant Yates Units 1-5, and Plant McManus 

Units 1 and 2 effective with the MATS compliance date, retirement of Plant Kraft Units 

1-4 by one year past the MATS compliance date, retirement of Plant Boulevard Units 2 

and 3 effective as of the date of the final order in this proceeding, and retirement of Plant 

Bowen Unit 6 by April 16, 2013;
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 Retirement of Plant McDonough-Atkinson Units 1 and 2 by 2012 and the addition of 

Units 4, 5, and 6 by 2012 for a net addition of approximately 2,003 MW as certified by 

the Commission in Docket No. 24506;

 Retirement of Plant Branch Unit 1 by April 16, 2015, Plant Branch Unit 2 effective 

October 1, 2013, and Plant Mitchell Unit 4C effective March 26, 2012, the date of the 

Commission’s final order in Docket No. 34218; 

 A switch to natural gas as the primary fuel for Plant Yates Units 6 and 7 and Plant Gaston 

Units 1-4; 

 A switch to PRB coal for Plant McIntosh and corresponding derate;

 Addition of two new nuclear units at Plant Vogtle (Units 3 and 4) for a combined 

increase in capacity of approximately 1,007 MW by 2018;

 Conversion of Plant Mitchell Unit 3 from coal to biomass as certified by the Commission 

in Docket No. 28158;

 Addition of 210 MW of solar resources from the GPASI as approved by the Commission 

on November 29, 2012 in Docket No. 36325; 

 Continuation of existing DSM programs, modification of certain existing DSM programs, 

decertification of one existing DSM program, and addition of one new DSM program as 

reflected in the 2013 DSM Application filed concurrently in Docket No. 36499;

 Unit Retirement studies of certain generating facilities that consider a range of scenario 

cases assuming certain fuel and carbon views through a matrix approach and support the 

Company’s MATS compliance strategy; 

 Capacity Mix Studies that show optimal capacity resource additions for the base case IRP 

assuming current regulations and no carbon emissions prices as well as results from 

scenarios with alternative fuel price forecasts and carbon price assumptions; and 

 Updated load and energy forecasts as well as an updated fuel forecast.

Furthermore, the IRP was tested under a range of sensitivity analyses to ensure that it will 

continue to meet customer needs if future conditions change. The different assumptions used in 

the sensitivity analyses are detailed in Section 6.5.3.
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1.14 CONCLUSION

In summary and as previously stated in Section 1.1, the Company seeks approval of:

1) Its 2013 Integrated Resource Plan and the associated Action Plan;

2) Decertification of Plant Branch Units 3 and 4, Plant Yates Units 1-5, and Plant McManus 

Units 1 and 2 effective by the MATS compliance date of April 16, 2015, decertification 

of Plant Kraft Units 1-4 one year past the MATS compliance date (by April 16, 2016), 

decertification of Plant Boulevard Units 2 and 3 effective as of the date of the final order 

in this proceeding, and approval of expedited decertification of Plant Bowen Unit 6 by 

April 16, 2013 as specified in the 2013 Decertification Application;

3) A switch to natural gas as the primary fuel for Plant Yates Units 6 and 7 and Plant Gaston 

Units 1-4; 

4) An amendment of the decertification date specified in the Commission’s final order in 

Docket No. 34218 for Plant Branch Unit 1 from December 31, 2013 to coincide with the 

decertification of Plant Branch Units 3 and 4; 

5) A certificate of public convenience and necessity for one new DSM program, a certificate 

amendment for three previously certified programs, decertification of one DSM program, 

and approval of updated program economics for all other previously certified energy 

efficiency DSM programs as further specified in the 2013 DSM Application in Docket 

No. 36499;

6) Reclassification of the remaining net book values of Plant Branch Units 3 and 4 and Plant 

Boulevard Units 2 and 3 as of their respective retirement dates to regulatory asset 

accounts and the amortization of such regulatory asset accounts ratably over a period 

equal to the respective unit’s remaining useful life approved in Docket No. 31958;

7) In the event the Commission does not approve the expedited decertification of Plant 

Bowen Unit 6, reclassification of the remaining net book value of Plant Bowen Unit 6 as 

of its respective retirement date to a regulatory asset account and the amortization of such 

regulatory asset account ratably over a period equal to the unit’s remaining useful life 

approved in Docket No. 31958;

8) Amortization of approximately $38 million of Plant Branch Units 3 and 4 and 

approximately $14 million of Plant Yates Units 6 and 7 environmental CWIP (which has 
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been reclassified as a regulatory asset in accordance with the Commission’s Order in 

Docket No. 31958) ratably over a three year period beginning January 2014; 

9) Reclassification of any unusable M&S inventory balance remaining at the unit retirement 

dates to a regulatory asset as identified in accordance with the Commission’s Order in 

Docket No. 31958 for recovery over a period to be determined by the Commission in the 

Company’s next base rate case following the unit retirements;

10) The capital costs the Company will incur for a portfolio of certain renewable 

demonstration projects (but not yet the recovery of such costs), as set out in the Selected 

Supporting Information section of Technical Appendix Volume 2; and

11) The capital and O&M costs (but not yet the recovery) of measures taken to comply with 

existing government-imposed environmental mandates, as set out in the Selected 

Supporting Information section of Technical Appendix Volume 2. 
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2 – INTEGRATED 

RESOURCE PLANNING 

PROCESS OVERVIEW
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SECTION 2 - INTEGRATED RESOURCE PLANNING PROCESS OVERVIEW

The development of an IRP for Georgia Power is part of a continuous planning process. Many 

different disciplines and areas of expertise from Georgia Power and Southern Company Services 

(“SCS”) are incorporated in this planning process. This process provides for an orderly and 

reasoned framework under which both supply-side and demand-side option evaluations are 

compared on an equitable basis to develop a plan that provides for reliable and economic electric 

energy to serve customers’ needs over the planning horizon. 

The Company developed a base case IRP using a combination of potential demand- and supplyside generation resources to meet the needs of customers as determined in the base case load and 

energy forecast. This base case plan represents an evaluation of the planning period with current 

laws and regulations. 

For the 2013 IRP, the Company is presenting the results of multiple scenario planning cases that 

evaluate the impacts of three different fuel price views as well as three different carbon views, 

each estimating the costs of potential carbon prices that represent additional pressure on carbon 

dioxide-emitting generation (e.g., greenhouse gas legislation or additional greenhouse gas 

regulation). Each scenario planning case is a separate and fully integrated resource plan and 

provides valuable insights into the potential impacts of different combinations of fuel prices and 

carbon prices over the planning period. 

Federal greenhouse gas legislation, if passed, or further development of additional greenhouse 

gas regulation, if promulgated by the EPA, will have a significant impact on national economic 

activity, fuel prices, and the electric utility industry. Given the differences in the electric 

generation fuel mix across the U.S., greenhouse gas legislation and/or regulation is also predicted 

to have large and disproportionate regional impacts, with particularly negative impacts for the 

southeastern U.S. due to its greater use of coal-fired electric generation compared to other 

regions. In order to evaluate these interactive and regional impacts, a national economic model 

was employed to evaluate the impacts of different fuel price forecasts and projections of carbon 

prices on national and regional economic activity. 
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This national economic model was also used to estimate the impacts of different carbon prices on 

the price of fuels, particularly natural gas, and to estimate the changes to the electric generation 

fleet across the U.S. that result from the scenario-specific prices of carbon and fuel. These 

impacts were extended to develop specific load and energy forecasts for each scenario. These 

load and energy forecasts were then used as the basis for developing a reliable and economic 

combination of potential demand- and supply-side generation resources to meet the needs of 

customers for each scenario.

2.1 CRITERIA FOR RESOURCE SELECTION

When a need for new capacity exists, the Company evaluates a combination of demand-side and 

supply-side resources to meet the need in an economical manner. The principal criterion for the 

development of the IRP is to maintain customer value — now and in the future. Customer value 

is maintained when the benefits of the services provided to customers exceed the cost of those 

services.

The best IRP is one that provides a high level of customer value while anticipating a broad range 

of potential changes. Therefore, Georgia Power considers additional objectives in the 

development of the IRP. These include:

 Flexibility - Can the plan be altered if the future is different than expected?

 Reliability - Does the plan provide reliable service for all customers?

 Long-Term Viability - Will the plan meet customer needs over the long term?

 Environmental - Does the plan ensure compliance with environmental regulations?

 Risk - Does the plan appropriately mitigate the risk of future changes in conditions?

 Shareholder Value - Will the plan provide shareholders with a fair return on their 

investment?
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2.2 OUTLINE OF THE PROCESS

The detailed process by which the IRP is developed is shown in Figure 1, and the components of 

this process are described below. This process is an integrated process where both the supplyside and the demand-side programs are evaluated simultaneously rather than independently.

Figure 1 - Detailed Integrated Resource Planning Process

The result of this process is the addition of demand- and supply-side options to serve customer

needs in an economical manner considering reliability, flexibility, and risk. Georgia Power’s 

Integrated Resource Planning Process

LOAD

 FORECAST

ECONOMIC PANEL

SUPPLY OPTIONS 

BUSBAR SCREENING

TECHNOLOGY 

REVIEW

FUEL FORECAST

RELIABILITY STUDY

(SERVM)

EXISTING FLEET 

OPERATIONS

VALUE OF SERVICE 

RELIABILTY

EXISTING FLEET 

OPERATIONS

PURCHASED POWER 

AGREEMENTS

BENCHMARK 

PLAN

(STRATEGIST)

SENSITIVITIES & 

PLANNING SCENARIOS

INTEGRATE SUPPLY & 

DEMAND SIDE OPTIONS

DSM SCREENING

(PRICEM)

FINAL 

INTEGRATED

RESOURCE PLAN

MARGINAL ENERGY 

COSTS

MARGINAL 

CAPACITY COSTS

RELIABILITY 

PROFILE (SERVM)

CUSTOMER 

RESEARCH

CUSTOMER 

RESEARCH

ENGINEERING COST 

ANALYSIS

PRELIMINARY IRP

FINANCIAL 

ASSESSMENT
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IRP process includes inputs from: (1) the Fuel Forecast; (2) the Economic Forecast; (3) 

Generation Technology Screening; (4) the Load and Energy Forecast; (5) the Reserve Margin 

Study; (6) demand-side program assessments; (7) existing resource screenings; (8) the 

Technology Cost Development Study; (9) the mix integration; and (10) the financial analysis and 

review steps.

2.2.1 Development of the Benchmark Plan

The left portion of Figure 1 shows how various inputs, such as customer preferences, reliability 

standards, technology updates, economic projections, and the latest load and energy forecast, 

feed into the development of a benchmark supply-side plan. The development of these inputs is 

described below.

2.2.1.1 Data Inputs

Fuel Forecast — The System develops both short-term (current year plus two) and long-term 

(year four and beyond) fuel and allowance forecasts. Short-term forecasts are updated monthly 

as part of the System’s fuel budgeting process, and marginal pricing dispatch procedures. The 

short-term forecasts are overseen by SCS Fuel Services. The long-term forecasts are initially 

developed in early spring of each year for use in system planning activities. The long-term 

forecasts are overseen by the System’s Planning Coordination Team. CRA International 

(“CRA”) is the modeling vendor used by the System to develop the long-term forecasts. The 

development of the long-term forecasts is a highly collaborative effort between CRA and the 

System (see Appendix I in the Resource Mix Study found in Technical Appendix Volume 1).

Economic Forecast — Moody’s Analytics’ macroeconomic forecast is the basis for inflation 

and cost of capital estimates. Moody’s Analytics developed a forecast of economic variables and 

demographic statistics for the state of Georgia. Key descriptive variables from the economic and 

demographic forecast of Georgia were used to produce the Budget 2013 Load and Energy 

Forecast (see Technical Appendix Volume 2).

Generation Technology Qualitative and Economic Screening — Feasibility studies for 39 

generation technologies were qualitatively screened by technology experts in SCS Research and 

Environmental Affairs. Various mature and emerging generating technologies were evaluated 
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for the feasibility of deployment within the System. For all technologies determined to be 

viable, recommendations were made for further consideration by declaring the “Status” of the 

respective technologies as “retained for further screening”. This process produced a select list of 

generating technology types that may be candidates for future plant additions.

Next, a preliminary, quantitative, economic and environmental screening evaluation was 

conducted utilizing a busbar life-cycle screening analysis. Busbar analysis compares total capital 

and operating costs of different types of generating technologies across a range of capacity 

factors. Busbar screening considers capital, fixed and variable O&M, fuels, and environmentalrelated costs and yields a comparison of the relative economics. The most promising 

technologies are subsequently reviewed in more detail, producing a recommendation of those 

types of generating units that are likely to be good candidates for inclusion in developing the 

final supply- side plan (see Section 6.4.2.).

Load and Energy Forecast — The Budget 2013 Forecast was started in the spring of 2012 and 

finalized in the fall of 2012. The load and energy forecasting process uses a combination of enduse and econometric analyses. The forecast is based on projections of economic growth, 

migration into the state, appliance efficiencies, competing fuel costs, and a variety of other 

projections. The principal sources of these projections are economic forecasting services, 

customer surveys, and computer models used by the Company. The forecast process is 

explained in detail in Section 3 of this document and in Technical Appendix Volume 2.

Reserve Margin Study — The retail operating companies currently use a 15 percent target 

system reserve margin guideline for long-term resource planning. This guideline was developed 

using a combination of mathematical models and studies, industry experience, and system 

operations input, and was approved in the most recent IRPs. Economic evaluation is a key 

component of setting the reserve margin target. An updated reserve margin study was recently 

completed for the 2013 IRP, and it affirmed the 15 percent longer-term system planning reserve 

margin target provides the appropriate balance between reliability and cost (see the Reserve 

Margin Study in Technical Appendix Volume 1).

Technology Cost Development Study — Current estimates are needed for cost, spending 

curves, emissions, and operating characteristics of the types of new generating units most likely 
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to be added to the system. Natural gas-fueled simple-cycle CT and CC units are the generating 

technologies likely to be added to the system in addition to renewable generation, new nuclear, 

and coal-fired plants with carbon capture and sequestration. Also, the CT cost is included in the 

marginal capacity cost used in evaluating demand-side options, existing unit changes, and load 

building programs. These estimates are inputs into a computer model that utilizes dynamic 

programming techniques to develop an optimum schedule of the types of capacity needed 

throughout the planning period.

2.2.1.2 Mix Process

A key part of the benchmark plan in Figure 1 is the determination of the mix of generating 

capacity types that economically and reliably serves the projected customer load. The mix 

process combines all of the information represented by the arrows pointing to the benchmark 

plan. The mix process uses dynamic programming techniques to determine the least-cost 

combination of units that will meet reliability constraints.

One of the first steps in developing this portion of the IRP is a least-cost analysis that minimizes 

the net present value of the revenue requirements for the moderate (or base case) level of 

customer load in order to develop the benchmark plan.

The result of this effort is the creation of the benchmark plan. The preliminary supply-side plan 

will be used as the base plan for the demand-side integration process. The final supply-side plan 

(or base case) includes the results of the demand-side analysis (see Figure 1, above). 

The key model used in the mix process is Strategist®. Strategist® employs a generation mix 

optimization module named PROVIEWTM (see Section 14, Attachment 14.1). Strategist® is 

used by approximately 70 other electric utilities. The major inputs of PROVIEWTM are: (1) 

future generating unit characteristics and capital cost; (2) the capital recovery rates necessary to 

recover investment cost; (3) capital cost escalation rates; and (4) a discount rate.

2.2.2 Assessment of Demand-Side Programs

Georgia Power identifies, screens, and assesses potential demand-side programs applicable to its 

service territory for inclusion in the IRP. This process uses a marginal cost approach to compare 
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the costs with the benefits of each demand-side program. Generation capacity and energy, 

transmission, distribution, and other costs and benefits are evaluated. The model used to 

estimate marginal energy cost (PROSYM) is the source of the marginal energy cost used in the 

model to evaluate DSM programs (PRICEM). These same marginal costs are used extensively 

in other supply-side evaluations associated with the IRP. Also, technology availability, market 

characteristics, customer acceptance, and customer response are considered in estimating the 

potential success, impacts, and costs of the programs. The process is described more fully in 

Section 5.

2.2.3 Existing Resource Evaluation

Georgia Power analyzes potential increases in output from existing generating units using 

marginal cost techniques similar to those used to analyze demand-side programs. As with DSM, 

the model used to estimate marginal energy cost (PROSYM) is the source of the marginal energy 

cost used in the model to evaluate existing resources. 

2.2.4 Integration and Development of the IRP

The integration step requires a re-examination of the need for generation additions identified in 

the benchmark plan as a result of including demand-side programs. After consideration of risk 

and uncertainty through sensitivity analyses and application of reasonable judgment, the 2013 

IRP is finalized.
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3 – BUDGET 2013

LOAD AND ENERGY 

FORECAST
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3-41

SECTION 3 - BUDGET 2013 LOAD AND ENERGY FORECAST

3.1 GENERAL FORECASTING AND ECONOMICS OVERVIEW

The Budget 2013 Load and Energy Forecast (“Budget 2013 Forecast”) is for Georgia Power. 

Unless otherwise noted, all data, figures, and statistics include both Georgia Power Company and 

the former Savannah Electric and Power Company, which was merged into Georgia Power 

Company effective July 1, 2006. 

The twenty-year forecast of energy sales and peak demand has been developed to meet the 

planning needs of the Company. The Budget 2013 Forecast includes the retail classes of 

residential, commercial, industrial, MARTA, and governmental lighting. The City of Hampton, 

included in the previous forecasts as a wholesale customer, is no longer served by Georgia 

Power. The baseline forecast was started in the spring of 2012 and completed in the fall of 2012.

The nation’s recovery from the Great Recession has been full of promise that, for the most part, 

has not yet materialized. Georgia’s economic recovery has been similar, but with a lag and, by 

some measures, weaker than the nation’s. For the past few years, the economy has shown signs 

of strength early in the year only to weaken by year end. Since the recession ended in mid-2009, 

real GDP has grown at an average annual rate of 2.3%, while Georgia’s corresponding real GSP 

has grown an average of 2.2% over the same period. The nation’s unemployment rate has fallen 

from its peak of 10.0% in 2009 to 7.8% as of December 2012, while the state’s rate, which 

peaked at 10.5% in 2010, has dropped to 8.6% as of December 2012. Both the state and nation 

would show significantly better numbers if the recovery had been typical of recoveries following 

previous recessions.

The slow recovery is reflected in Georgia Power’s energy sales statistics for the past few years. 

Weather normalized total energy sales for 2012 were nearly 0.5% below the prior year’s level 

and remain more than 3.3% below the previous peak in 2007. The major drop since the 

recession has been in industrial sales, which remain almost 9.2% below their pre-recession level 

on a weather-normalized basis in spite of healthy growth in 2010 and moderate growth in 2011. 
3-42

In 2012, commercial and residential energy sales levels were 1.2% below and 0.3% below 2007 

levels, respectively.

Although underperforming for the past few years, Georgia’s economy is expected to regain 

strength over the next several years. Surveys show that the state remains an attractive place to do 

business. Recent announcements of companies’ plans to locate or expand in the state include 

those by Baxter International and Caterpillar which are expected to bring 2,900 jobs to the state. 

Living costs also remain attractive relative to many states. The demographic forces that once 

propelled the state to near the top of the economic growth league should strengthen once home 

price adjustments break the housing logjam that nearly halted net migration. As the economy 

improves, energy sales will follow suit. Total energy sales are currently projected to grow at an 

average annual rate of 1.2% from 2013 to 2020. Residential sales will be the strongest of the 

three major customer classes with growth projected to average 1.4% per year; industrial and 

commercial are projected to average 1.2% and 1.1%, respectively. Peak demand is projected to 

grow an average of 1.5% per year from 2013 to 2020.

3.2 FORECAST ASSUMPTIONS AND METHODS

The Budget 2013 Forecast assumptions were developed through a joint effort of Georgia Power 

and SCS. The forecast was developed through careful consideration and methodical 

organization of key demographic and economic variables that have been demonstrated to be 

significant indicators of energy consumption. Major assumptions included the economic outlook 

for the U.S. and Georgia, energy prices, and market profiles for class end uses.

The economic forecast gives a description of the economy for the next 20 years and includes 

many elements of the economy, such as gross product, population, employment, commercial 

building square footage, and industrial production. The economic forecast for Budget 2013 

Forecast was obtained from Moody’s Analytics, a national provider of economic data and 

forecasts.

The economic models used to produce both short and long-term energy and demand forecasts 

test a variety of economic and demographic variables as drivers of energy use. Retail prices for 

electricity and natural gas, for example, are drivers of energy use. The short-term forecasting 
3-43

models incorporate retail electricity prices, while the long-term models allow both electricity and 

gas prices to affect the purchasing decisions of customers. Price projections of the alternative 

fuels that energy-consuming devices use to support a consumer need, business purpose, or 

industrial process are developed from internal processes so that device choice through consumer 

behavior can be modeled. 

Weather, income, employment, historical load data, and industry standards for electrical 

equipment are among the other variables used in the forecasting models. Both the short-term and 

the long-term energy models are based on “normal” weather - the twenty-year average of 

Cooling Degree Days (“CDD”) and Heating Degree Days (“HDD”).

Short-term energy projections are based on linear regression models developed for the various 

energy classes. The details of these regression models can be found in Section 4 of the Budget 

2013 Forecast in Technical Appendix Volume 2.

The long-term models for the major classes are end-use models. The Residential End-Use 

Energy Planning System (“REEPS”) model is used for the residential class, the Commercial 

End-Use Model (“COMMEND”) is used for the commercial class, and the Industrial End-Use 

Forecasting Model (“INFORM”) is used for the industrial class. These are discussed in greater 

detail in Section 5 of the Budget 2013 Forecast included in Technical Appendix Volume 2.

Governmental lighting and MARTA forecasts are based on econometrics and information from 

Georgia Power field personnel.

The results of the short-term and long-term models are integrated into a unified forecast. In the 

Budget 2013 Forecast, the short-term forecast results were used for 2013 through 2015 and long 

term forecast results were used for 2016 through 2032. Additional information on methodology 

can be found in Section 3 of the Budget 2013 Forecast in Technical Appendix Volume 2.
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4-45

4- COMPARISON OF THE 

FORECAST WITH 

EXISTING RESOURCES
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SECTION 4 - COMPARISON OF THE FORECAST WITH EXISTING RESOURCES

4.1 SYSTEM AND GEORGIA POWER RESOURCES

The System carries reserves in order to maintain a desired level of reliability in the face of many 

uncertainties, the most significant of which are load growth, weather, and generating unit 

outages. The current System long-term planning target reserve margin requirement is 15 percent 

of the total System load. In most years, the System operating companies peak at different times. 

This results in a lower System peak than the sum of each operating company’s peak demands. 

Due to this load diversity, each operating company can carry lower reserves (approximately 13.5 

percent) and still maintain the target planning reserve margin of 15 percent for the System. As a 

member of the System, Georgia Power shares reserves with the other operating companies. 

Georgia Power and the System are currently projected to have adequate reserves through 2022. 

Without reserve sharing, the Company’s first year of capacity need is 2021. Georgia Power will 

provide an adequate and cost-effective level of reliability to its customers. 

See Table 4.1.1, Table 4.1.2 and Figure 4.1 in the IRP Main Document Reference Tables section 

of Technical Appendix Volume 1 for additional details. 
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5 – DEMAND-SIDE

PLAN
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5-51

SECTION 5 - DEMAND-SIDE PLAN

This section summarizes the process used to assess demand-side resources for Georgia Power’s 

2013 IRP filing. Included in this section are:

 A review of significant events since the Company’s 2010 IRP filing that are relevant to 

the assessment and screening of demand-side resources; 

 A discussion of newly proposed and expanded DSM programs and activities;

 A discussion of the regulatory treatment of DSM program costs and the Additional Sum; 

and

 A presentation of the economic results of DSM programs for this IRP.

The identification and evaluation of demand-side resources for inclusion in this IRP involves 

market considerations, such as customer acceptance and applicability, customer economics, and 

electric supply system economics. The process uses marginal electric supply costs in the 

analysis. The Company followed the process outlined in the Commission’s IRP Rules and the 

Nine Step process outlined in the 2010 IRP Order which is discussed in more detail in later 

sections of this filing.

5.1 REVIEW OF SIGNIFICANT EVENTS SINCE PREVIOUS IRP FILING

Since the Company’s 2010 IRP filing, certain events have affected the screening of demand-side 

resources. These events are described below:

5.1.1 2010 IRP Filing Approval

In the 2010 IRP Order, the Commission approved and certified seven of the Company’s 

proposed DSM programs at an agreed upon three-year ramp up to the Commission Staff’s 

proposed annual participation levels. The 2010 IRP Order also approved program 

implementation plans for the following programs:

Residential Programs:

 Lighting & Appliance

 New Home

 Home Energy Improvement

 Refrigerator/Freezer Recycling
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 Water Heating

Commercial Programs:

 Custom Incentive

 Prescriptive Incentive

Additionally, as part of the implementation of the seven new programs, a program evaluation 

plan was developed and filed with the Commission in 2011, and the program evaluations were 

subsequently completed in 2012.

5.1.2 Program Evaluation Results

As part of the stipulated agreement between the Company and the Commission included in the 

2010 IRP Order, each of the seven newly certified DSM programs were to have a process and 

load impact evaluation performed prior to the 2013 IRP. Nexant was selected by Georgia Power 

to perform the program evaluations. Program evaluations were completed and filed in December 

28, 2012. The results of the program evaluation were considered in the development of the 2013 

IRP and will be considered in future DSM program plans.

5.1.3 2013 IRP Demand Side Management Working Group (“DSMWG”) Meetings

The Company met with the DSMWG four times in 2011 and four times in 2012 in accordance 

with the Nine Step process approved by the Commission in the 2010 IRP Order. Additionally, 

the Company met with sub-committees twice in 2012 to discuss DSM program concepts and to 

discuss modeling of a DSM case proposed by certain members of the DSMWG. Finally, the 

Company conducted several telephone conference calls and shared data with the DSMWG 

leading up to the 2013 IRP filing.

5.1.4 2013 Nine Step DSM Planning Process

As part of the 2010 IRP Final Order, the Commission approved the Nine Step DSM planning 

process that guided the development of the Company’s 2013 IRP DSM plan. 

Specifically, the Nine Step process stated:
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1. Georgia Power, using an RFP process, will select a third party consultant to assist in the 

Technology Catalog update, research active programs nationally, and assist in 

developing proposed programs. 

2. Georgia Power will utilize a technical and economic potential study for Georgia Power’s 

service territory to assist in targeting DSM programs in the areas where the highest 

market potential exists. For the 2013 IRP, Georgia Power will file a new energy 

efficiency potential study one year in advance of the 2013 IRP filing. 

3. Georgia Power, along with its consultant, will update the DSM Measures in the 

Technology Catalog for the purpose of producing the energy efficiency potential study. 

The starting point will be the 2010 IRP Technology Catalog. Additional technologies 

will be added once Georgia Power’s consultant is chosen and begins its work. The 

Company will then use the results of the potential study to identify a list of DSM 

measures that passes the TRC test to be used in program plans. This list of measures will 

then be presented to the DSMWG. The Company will work closely with members of the 

DSMWG through this process, and DSMWG members may also propose new measures to 

be added at any point in the measure evaluation process. 

For each DSM measure that passes the TRC test included in the Technology Catalog, the 

utility shall provide all members of the DSM Working Group with the following 

information:

(i) A brief description of the measure;

(ii) Measure costs and the exact source for these costs;

(iii) Measure kW and kWh load impacts and the exact source for such load impacts;

(iv)The forecast of electric and other avoided costs used to value measure or program 

savings;

(v) Measure useful life and the exact source for measure life data;

(vi)Measure levelized cost per lifetime kWh saved (for energy efficiency measures 

only);

(vii) Size of the eligible market;

(viii) Forecast of achievable market penetration;

(ix) Current saturation of the energy efficiency or demand response measure and the 

source of this data;

(x) Assumptions on participant benefits, if any, other than electricity savings; and

(xi) Any other supporting data deemed pertinent by the utility.

The update of the Technology Catalog will be completed by January 1, 2012.

4. Once the Technology Catalog is updated, Georgia Power will propose the bundling of 

measures into programs. Georgia Power, along with its consultant, will prepare a 

proposed program presentation for review by the DSMWG. Any other member of the 

DSMWG may propose programs as well. The DSMWG will meet to facilitate sufficient 

discussions on the programs to be evaluated. An electronic version of this presentation 

will be provided to the DSMWG at least two weeks prior to the in-person meeting where 

this information will be presented.
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5. As part of the program design development, the Company intends to collect and share 

customer data/feedback with the DSMWG. In the event that the Company reasonably 

determines that certain data/feedback cannot be shared with the DSMWG, the DSMWG 

will be made aware of that withholding and the reasons for that withholding. This could 

include information obtained from surveys, customer focus groups, impact and process 

evaluations, Georgia Power Account Representatives, etc.

6. Once the Company determines which programs are to be analyzed, it will perform an 

economic screening of the programs in greater detail using the EnerSim and PRICEM 

models. For each program proposed by a member of the DSMWG that Georgia Power 

decides not to analyze, Georgia Power shall provide to the DSMWG justification for its 

decision. The economic screening will include RIM, participants test (“PT”), total 

resource costs tests (“TRC”), and the Program Administrator Test for use in program 

design development. The results of the economic screening will be shared with the 

DSMWG for discussion. This economic screening will be presented to the DSMWG no 

later than third quarter of 2012.

7. Attempts to reach consensus and finalize all programs to be proposed for implementation 

in the 2013 IRP must be completed by third quarter of 2012 in order to allow the 

Resource Planning group adequate time for inclusion in their process. Preliminary costeffectiveness tests using PRICEM for revenue and avoided costs inputs will be developed 

for each program. These programs will be divided into programs that are passive 

(energy efficiency programs whose response is not controlled) versus active (demand 

response programs that are generally under dispatch control of the utility). Load 

reductions associated with passive programs will be used to adjust the load and energy 

forecast. Capacity associated with active programs will be modeled as resources. This 

information will be evaluated as two different system configurations with a base case 

without any new DSM (the base case would include the effects of continuation of existing 

DSM programs) and a Company DSM change case with both passive and active new 

DSM. 

8. As part of the sensitivity analysis, the Company will also analyze at least one aggressive 

DSM change case developed with the assistance of the DSMWG. The aggressive DSM 

change case(s) could include technically viable and economically efficient DSM 

programs and resources that were not included in the Company DSM change case. The 

aggressive DSM change case(s) could also include higher penetrations of the DSM 

programs proposed in the Company DSM change case.

9. The Company will use the difference in costs between the base case and the DSM change 

case configurations to determine the avoided generation cost impact of the DSM 

programs in each DSM change case. As the final step, the cost effectiveness tests 

mentioned in item 6 (above) will be calculated based on the inputs and adjustments from 

the system tools. Revenue impacts will be based on current rates and escalations based 

on the Company’s financial projections adjusted for the DSM cost impacts. The avoided 

generation costs from the system tools and the avoided Transmission and Distribution 

(“T&D”) revenue requirements as estimated by PRICEM will be used to calculate the 

benefits of the RIM, TRC and Program Administrator test for each DSM change case. 
5-55

The projected deadline for including new programs in the system planning process is mid 

2012.

The Company has satisfied the requirements outlined in the Nine Step process. Particularly 

noteworthy are the requirements of Steps 2 and 3. The Company filed with the Commission a 

new energy efficiency potential study on January 31, 2012 (as required by Step 2) along with an 

update filed on December 4, 2012. The Company also completed the update of the Technology 

Catalog by January 1, 2012 (as required by Step 3) and shared the information with the 

Commission Staff and members of the DSMWG on December 29, 2011, along with an update on 

January 4, 2013.

Additionally, the Company met with Commission Staff throughout the two year (2011-2012) 

planning phase of the 2013 IRP to provide updated progress toward completing the Nine Step 

process. 

5.1.5 2013 IRP Avoided Cost/Fuel Price Decreases 

Future estimated costs for fuel continue to be dynamic and, therefore, the avoided costs related to 

future resources are dynamic. The avoided fuel cost savings from customers installing DSM 

measures in the 2013 IRP have declined from the 2010 IRP. These changes in avoided cost 

savings have a significant negative impact on the economics of the Company’s current and 

proposed DSM programs. As is discussed later in this section, Total Resource Cost (“TRC”) 

Test results declined and Ratepayer Impact Measure (“RIM”) Test results worsened as well, 

causing concerns for the Company in its efforts to balance the economic benefits these programs 

have for participating customers with the rate impacts caused by the programs.

5.2 DISCUSSION OF CURRENT AND PROPOSED DSM PROGRAMS

5.2.1 Continuation and Expansion of Current Certified DSM Programs and 

Addition of New Certified DSM Program

5.2.1.1 Residential DSM Programs

In its 2013 DSM Application, the Company is requesting the following actions or adjustments 

for the following certified residential DSM programs:
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Residential Programs

 EarthCents New Home program (formerly known as High Efficiency New Home 

program) - Amend the New Home certificate as a result of the expansion of the program.

 EarthCents Home Energy Improvement program (formerly known as Residential 

Existing Homes program) - Approve updated program economics.

 EarthCents Residential Lighting and Appliance program - Amend the certificate to split 

the program into two individual programs:

o EarthCents Appliance program

o EarthCents Lighting program

 EarthCents Refrigerator/Freezer Recycling program - Approve updated program 

economics.

 EarthCents Power Credit program – No changes requested.

 EarthCents Residential Water Heating program - Decertify and combine goals with the 

EarthCents Home Energy Improvement program. 

EarthCents New Home Program. This program focuses on a whole-house approach to 

improving the energy efficiency of new homes, promoting the installation of energy efficient 

measures in new home construction, and improving the performance of participating homes to at 

least 15 percent above the current Georgia State Energy Code at the time the home is built. 

Additionally, it will promote improvements in individual measures such as high efficiency 

electric heating and cooling equipment and heat pump water heaters. 

Details of the program continuation are outlined in the ten-year Program Plan found in the 2013 

DSM Application.

The 2014 expected energy reductions and cost-effectiveness of the EarthCents Residential New 

Home Program are as follows:

Program

Demand 

Reduction 

(kW)

Energy 

Reduction 

(kWh)

Ratepayer 

Impact Measure 

Test

Total Resource 

Cost Test

Program 

Administrator 

Test

Participants 

Test

Societal Test

EarthCents 

Residential New 

Home

685 5,186,430 $ (4,444,597) $ 1,958,491 $ 3,005,808 $ 6,403,089 $ 2,129,618

Note: Economic test results are the NPV over the life of the measure.
5-57

EarthCents Home Energy Improvement Program. This program promotes a comprehensive, 

whole-house approach to improving the energy efficiency and comfort of existing homes. It also 

offers an alternate path that allows customers to make improvements to individual areas of the 

thermal envelope and equipment in their homes as well. The features of the former Residential 

Water Heating Program which were also being marketed through this program for years 2011 –

2013 will be included in this program. 

Details of the program continuation are outlined in the ten-year Program Plan found in the 2013 

DSM Application.

The 2014 expected energy reductions and cost effectiveness of the EarthCents Residential Home 

Energy Improvement Program are as follows:

EarthCents Lighting Program. This program promotes the purchase and installation of energy 

efficient lighting and lighting fixtures through customer education, retailer partnerships/training, 

promotional giveaways of high efficiency lights, and customer incentives.

Details of the program continuation are outlined in the ten-year Program Plan found in the 2013 

DSM Application.

The 2014 expected energy reductions and cost effectiveness of the EarthCents Residential 

Lighting Program are as follows:

Program

Demand 

Reduction 

(kW)

Energy 

Reduction 

(kWh)

Ratepayer 

Impact Measure 

Test

Total Resource 

Cost Test

Program 

Administrator 

Test

Participants 

Test Societal Test

EarthCents 

Residential Home 

Energy 

Improvement

6,054 10,918,075 $ (10,746,370) $ 5,246,089 $ 4,173,049 $ 15,992,459 $ 5,589,247

Note: Economic test results are the NPV over the life of the measure.

Program

Demand 

Reduction 

(kW)

Energy 

Reduction 

(kWh)

Ratepayer 

Impact Measure 

Test

Total Resource 

Cost Test

Program 

Administrator 

Test

Participants 

Test Societal Test

EarthCents 

Residential 

Lighting

1,325 13,918,542 $ (5,377,548) $ 2,958,287 $ 3,720,942 $ 8,335,835 $ 3,110,253

Note: Economic test results are the NPV over the life of the measure.
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EarthCents Appliance Program. This program promotes the purchase and installation of 

energy efficient appliances through customer education, retailer partnerships/training, and 

customer incentives.

Details of the program continuation are outlined in the ten-year Program Plan found in the 2013 

DSM Application.

The 2014 expected energy reductions and cost effectiveness of the EarthCents Residential 

Appliance Program are as follows:

EarthCents Refrigerator/Freezer Recycling Program. This program aims to eliminate 

inefficient or extraneous refrigerators and freezers in an environmentally safe manner and 

produce cost-effective long-term energy and peak demand savings. The program focuses on 

increasing residential customer awareness of the economic and environmental costs associated 

with running inefficient, older refrigerators and freezers. The program provides cash incentives, 

free pickup, and recycling for qualifying equipment. 

Details of the program continuation are outlined in the ten-year Program Plan found in the 2013 

DSM Application.

The 2014 expected energy reductions and cost effectiveness of the EarthCents 

Refrigerator/Freezer Recycling Program are as follows:

Program

Demand 

Reduction 

(kW)

Energy 

Reduction 

(kWh)

Ratepayer 

Impact Measure 

Test

Total Resource 

Cost Test

Program 

Administrator 

Test

Participants 

Test Societal Test

EarthCents 

Residential 

Appliance

399 8,043,589 $ (5,036,188) $ 5,389,529 $ 3,043,625 $ 10,425,716 $ 5,542,454

Note: Economic test results are the NPV over the life of the measure.

Program

Demand 

Reduction 

(kW)

Energy 

Reduction 

(kWh)

Ratepayer 

Impact Measure 

Test

Total Resource 

Cost Test

Program 

Administrator 

Test

Participants 

Test Societal Test

EarthCents 

Refrig/Freezer 

Recycling

827 17,519,548 $ (10,367,781) $ 4,251,958 $ 3,672,626 $ 14,619,739 $ 4,482,280

Note: Economic test results are the NPV over the life of the measure.
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EarthCents Power Credit Program. The Power Credit program is a residential load control 

program that currently has approximately 53,000 participants. Some of the participating homes 

have more than one direct load control unit switch to control multiple Heating, Ventilation and 

Air Conditioning (“HVAC”) units. The Power Credit program allows Georgia Power to cycle 

HVAC systems during periods of high system capacity constraints and high energy costs. 

HVAC energy is thereby shifted into off-peak periods that typically have lower demands and 

energy costs. The program provides approximately 100 MW of demand reduction. 

Georgia Power is currently replacing the low frequency radio receiver load control technology 

with 900 MHz receivers. This replacement should be completed by the end of 2013.

EarthCents Residential Water Heating Program. This program will be decertified and 

further activity will be included within the EarthCents Home Energy Improvement Program.

5.2.1.2 Commercial DSM Programs

In its 2013 DSM Application, the Company is also requesting the following actions or 

adjustments for the following certified commercial DSM programs:

Commercial Programs

 EarthCents Commercial Prescriptive Incentive program – Approve updated program 

economics. 

 EarthCents Commercial Custom Incentive program – Amend the certificate.

 EarthCents Small Business program – Grant a new certificate. 

The prescriptive and custom commercial programs will be marketed and advertised as one 

program to commercial customers for ease of implementation and to avoid market confusion. 

They will be marketed as the EarthCents Commercial Energy Efficiency Program to new and 

existing customers but will continue to have separate budgets, energy savings targets, and 

economic analyses. 

EarthCents Commercial Prescriptive Incentive Program. This program promotes the 

purchase of eligible high-efficiency equipment installed at qualifying customer facilities. 
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Customer incentives will be offered through this program to reduce the incremental cost to 

upgrade to high-efficiency equipment and measures over standard efficiency options.

Details of the program continuation are outlined in the ten-year Program Plan found in the 2013 

DSM Application.

The 2014 expected energy reductions and cost effectiveness of the EarthCents Commercial 

Prescriptive Incentive Program are as follows:

EarthCents Commercial Custom Incentive Program. This program provides a platform for 

comprehensive energy efficiency projects in larger facilities that go beyond single measures and 

common efficiency practices. The program does not define a specific list of eligible measures 

but bases participation and customer incentives on the verifiable energy savings resulting from 

the measures implemented. Measurement and verification procedures will vary depending on 

the energy efficient products installed. 

Details of the program continuation are outlined in the ten-year Program Plan found in the 2013 

DSM Application.

The 2014 expected energy reductions and cost effectiveness of the EarthCents Commercial 

Custom Incentive Program are as follows:

EarthCents Small Business Program. This program promotes the purchase of eligible highefficiency equipment for small commercial businesses that are either more similar in 

Program

Demand 

Reduction 

(kW)

Energy 

Reduction 

(kWh)

Ratepayer 

Impact Measure 

Test

Total Resource 

Cost Test

Program 

Administrator 

Test

Participants 

Test Societal Test

EarthCents 

Commercial 

Prescriptive

8,259 26,865,348 $ (6,395,600) $ 10,759,642 $ 17,277,218 $ 17,155,243 $ 11,319,134

Note: Economic test results are the NPV over the life of the measure.

Program

Demand 

Reduction 

(kW)

Energy 

Reduction 

(kWh)

Ratepayer 

Impact Measure 

Test

Total Resource 

Cost Test

Program 

Administrator 

Test

Participants 

Test Societal Test

EarthCents 

Commercial 

Custom

44,520 205,476,528 $ (27,775,186) $ 133,099,669 $ 210,752,047 $ 160,874,855 $ 139,578,031

Note: Economic test results are the NPV over the life of the measure.
5-61

construction to residential buildings or just of a smaller nature. Customer incentives offered 

through this program serve to reduce the incremental cost to upgrade to high-efficiency 

equipment or measures over standard efficiency options. Some of the measures in the program 

were modeled after the EarthCents Home Energy Improvement program. The remaining 

measures included are from the other two commercial programs with different rebate levels for 

the smaller commercial customers. Customers who are eligible for the Small Business program 

will also be eligible to participate in the Commercial Custom Incentive and Commercial 

Prescriptive Incentive programs.

Details of the program are outlined in the ten-year Program Plan found in the 2013 DSM 

Application.

The 2014 expected energy reductions and cost effectiveness of the EarthCents Small Business 

Program are as follows:

Each of the ten-year DSM Program Plans allows for ongoing review and modification of 

program design features through regular program monitoring as well as the formal program 

evaluation plan in an effort to maximize energy savings while maintaining economic efficiency. 

Any significant changes to program design in support of market conditions or program 

economics will be included with ongoing reports filed with the Commission, program evaluation 

filings, and/or IRP updates as needed. Additionally, as new measures and technologies evolve 

during the 10 year filed program life, the Company may add them to these programs. Any new 

measures being added would have to follow the same economic screening process as those 

approved by the Commission and the Commission would be made aware of any additions prior 

to the Company offering the new measures to customers.

Program

Demand 

Reduction 

(kW)

Energy 

Reduction 

(kWh)

Ratepayer 

Impact Measure 

Test

Total Resource 

Cost Test

Program 

Administrator 

Test

Participants 

Test Societal Test

EarthCents Small 

Business

2,569 8,647,047 $ (4,760,290) $ 6,347,198 $ 9,547,237 $ 11,107,489 $ 6,646,531

Note: Economic test results are the NPV over the life of the measure.
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5.2.2 Continuation of the Weatherization Assistance for Low Income Customers 

Program

The Weatherization Assistance for Low Income Customers program began in January 1996. The 

program was designed to provide monetary assistance to Resource Services Ministries (“RSM”) 

and the Georgia Environmental Finance Authority (“GEFA”) to augment their existing 

weatherization assistance efforts for low income customers. 

The program currently provides annual funding of $1.75 million to GEFA and $250,000 to RSM. 

Georgia Power plans to continue the funding of the Weatherization Assistance for Low Income 

Customers program at its current annual funding level of $2 million through December 31, 2016. 

5.2.3 Energy Efficiency Information Programs 

Energy efficiency informational brochures, websites and events developed by Georgia Power 

assist customers in learning about using energy more efficiently. Specific program information 

costs are handled in the applicable program budgets and are included in that particular program’s 

implementation. General energy efficiency awareness efforts using many different media (TV, 

radio, websites, and print ads) help customers understand the general benefits of using energy 

efficiently and directs them to specific programs. 

Georgia Power has increased its focus on using online information tools and social media, such 

as Twitter and Facebook, to engage interested parties in energy efficiency discussions.

5.2.4 Energy Audits, Energy Efficiency Information Line and One-On-One 

Energy Efficiency Assistance

The Company also provides a number of other avenues for one-on-one customized assistance to 

customers to help them better understand their energy usage and to identify energy efficiency 

opportunities. Additionally, in-home (more than 8,000 in 2012), in-facility (more than 1,500 in 

2012) and on-line (more than 86,000 in 2012) energy audits are offered to customers to assist in 

identifying energy and money savings opportunities, and also serve as marketing channels to 

direct customers to participate in energy efficiency programs. Furthermore, over 40,000 calls a 

year are received through the Company’s energy efficiency hotline from residential customers 

seeking energy efficiency advice. One-on-one assistance is also offered and is typically directed 
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toward helping the Company’s larger commercial and industrial customers through its key 

account managers; however, assistance can be provided to any customer by virtually any 

employee in the Company.

5.2.5 Energy Efficiency Awareness Initiative

Georgia Power’s Energy Efficiency Awareness initiative promotes the benefits of energy 

efficiency and educates customers about specific ways to save money and energy. The 

Commission-approved budget for this activity is $4.4 million annually for years 2011 through 

2013. This budget has historically supported awareness in the residential market. Going forward 

there is a need to also raise awareness in the commercial markets. Georgia Power requests an 

increase in this annual budget to $5.4 million for years 2014 through 2016. This increase request 

keeps the residential campaign at $4.4 million annually and adds $1 million annually for 

commercial general awareness.

Georgia Power uses direct marketing channels to efficiently reach its customer base. Television, 

radio, print, internet, billboard, and local office advertising and direct mail are the primary 

channels used. The Company has developed a number of online tools and has placed them on its 

website to enhance customers’ learning about energy efficiency. Customers are invited to visit 

georgiapower.com to learn ways to save energy through general energy efficiency information, 

helpful tips and specific information about energy efficiency programs offered by Georgia 

Power. In 2012, more than 466,000 visitors accessed the Company’s energy efficiency 

information website and there were more than 86,000 on-line audits. Social media is also used to 

communicate with online customers, including Facebook, Twitter and YouTube.

Additionally, Georgia Power has re-initiated its classroom presence through the Learning Power 

program. Currently, curriculums to support energy and energy efficiency understanding from a 

grass roots perspective have been developed or are under development for grades K-12. 

For calendar year 2012, Education Coordinators completed more than 2,700 Learning Power 

events for more than 70,000 students.
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5.2.6 Demand Response Tariffs

For many years, Georgia Power has offered its customers a menu of demand response tariffs, 

such as: 

 Real Time Pricing offers customers marginal pricing for incremental load – as prices 

increase, customers can respond by reducing their demand; 

 Demand Plus Energy Credit is an interruptible service tariff that provides customers 

with a demand credit for the potential demand reduction plus provides an energy credit 

when DPEC is called; and

 Time of Use tariffs provide customers with pricing signals during different periods of the 

day that closely reflect the marginal cost of the energy in the specific time period (peak 

and off-peak) and encourage customers to modify their usage accordingly.

5.3 DSM RESOURCE ASSESSMENT AND INITIAL COST EFFECTIVENESS 

SCREENING

5.3.1 Assessment and Screening Methodology

The assessment and screening methodology for DSM measures used in this IRP included 

identifying DSM programs and measures with detailed input from the DSMWG. Additionally, 

economic evaluations were performed for each program that was passed to economic screening 

to determine the program cost-effectiveness based on the industry-standard benefit/cost tests and 

as required by the Commission IRP rules. The tests conducted are the RIM, TRC, Participants 

Test (“PT”), Program Administrator Cost Test (“PACT”), and Societal Cost Test (“SCT”). RIM 

assesses fairness and equity by measuring what happens to customer bills or rates due to changes 

in utility revenues and operating costs caused by the program. The TRC test assesses economic 

efficiency and societal impact by measuring the net costs of a demand-side management program 

as a resource option based on the total costs of the program, including both the participants’ and 

the utility’s costs. The PT assesses the impact on a program participant by measuring the 

quantifiable benefits and costs to the customer due to participation in a program. The PACT 

assesses the net costs of a demand-side management program as a resource option based on the 

costs incurred by the program administrator (including incentive costs) and excluding any net 
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costs incurred by the participant. The SCT is a variant of the TRC test and includes an adder to 

avoided fuel costs to simulate environmental externalities. 

The Company met with, discussed, and shared presentations related to DSM program design 

details with the DSMWG at multiple meetings in 2011 and 2012. A smaller sub-group of the 

DSMWG met and identified the program concepts and measures considered for economic 

screening in support of the 2013 IRP development. Input from the sub-group participants was 

used in developing the list of programs to analyze. This list was shared with the larger DSMWG 

requesting feedback or any additional input to this process. Consensus on programs to include in 

the analysis was reached with the DSMWG. The preliminary results of the program economic 

screening were also shared with the DSMWG in advance of this filing. 

5.3.2 DSM Program Economic Screening Policy

The Company continues to follow the Commission’s economic screening policy outlined in the 

2004 IRP Final Order, Docket No. 17687, which requires the Company to offer a DSM plan that 

minimizes upward pressure on rates and maximizes economic efficiency. Additionally, the 

Company’s DSM plan treats DSM as a priority resource. In fact, the first step in the Company’s 

IRP process is to reduce the Company’s energy and demand forecast by the recommended 

proposed case DSM plan (“Proposed Case”) energy and demand impacts prior to developing the 

supply-side alternatives. The recommended Proposed Case cost-effectiveness results presented 

herein are representative of modifications to current DSM programs for which the Company 

seeks continued and amended certification in Docket No. 36499. However, due to the decline in 

avoided costs since the 2010 IRP, these rate impacts will be larger than the DSM programs 

approved in the 2010 IRP. At the same time, while the DSM programs provide TRC benefits, 

such benefits are not as large as in the 2010 IRP due to the decline in avoided costs. The 

recommended Proposed Case DSM programs will average almost $187 million (NPV over the 

life of the measures) in TRC benefits annually but will, on average, put $82 million of upward 

pressure on rates (NPV over the life of the measures) annually for years 2014 - 2016. 

The aggressive sensitivity case (“Aggressive Sensitivity Case”) cost-effectiveness results are 

also presented herein, as outlined in the Nine Step process. The Aggressive Sensitivity Case is 

not recommended by Georgia Power and is not a DSM plan that should be approved by this 
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Commission due to the significant increase in customers’ bills and poor economic efficiency, 

relative to the upward pressure that would result. The Aggressive Sensitivity Case sensitivity 

includes programs from the recommended Proposed Case but with customer participation at 

higher penetration levels and associated higher budgets, as well as additional programs, 

measures, and associated budgets to help reach almost 12.5 percent cumulative energy savings 

over ten years based on the Budget 2012 forecast. 

At the request of some members of the DSMWG, the Company agreed to analyze another case, 

identified as the DSMWG Advocacy sensitivity case (or “Advocacy Sensitivity Case”), which 

achieved a 9.5 percent cumulative energy savings over ten years when compared to the Budget 

2012 forecast. The results of this sensitivity case were shared with a sub-committee of the 

DSMWG advocates in August 2012 and with the entire DSMWG in September 2012.

The higher levels of market penetration in both the Advocacy and Aggressive Sensitivity Cases 

ultimately result in average annual rate impacts of approximately $461 million and $650 million 

(NPV over the life of the measures), respectively, for years 2014 - 2016 over the alternative 

supply-side resource plan. These plans, if implemented as analyzed, would increase customers’ 

rates approximately six to eight times more than the Company’s recommended Proposed Case, 

while only increasing the economic efficiency (or TRC benefits) by about two and a half to three 

and a half times, respectively, for the same timeframe. 

5.3.3 Data Development

In developing its list of DSM measures for inclusion in programs for initial screening, the 

Company conducted a comprehensive review of technical information sources for demand-side 

and energy-efficiency technologies. This review included evaluation of the Company’s previous 

IRP filings, as well as reviews of new sources of information. Additional input was provided by 

the DSMWG members. Company representatives who work closely with Georgia Power’s 

customers were also surveyed for their input. Additionally, customer feedback from surveys was 

reviewed as a source of information for program additions and improvements. Information 

gathered was shared with the DSMWG in the program development discussions. A compilation 

of the qualitative screening of DSM measures is included in Technical Appendix 2. 
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5.3.3.1 Residential Technology

More than 100 residential DSM measures within nine programs were identified for program 

economic screening. These measures provided potential energy savings through: 

 customer behavior improvements;

 compliance with state standards and codes;

 increased energy efficiency for electric appliances;

 electric space cooling and heating equipment;

 electric lighting;

 electric water heating; and

 heating and cooling savings resulting from improvements to the home’s thermal shell and 

increased equipment efficiency.

In addition to specific measures, the building type (new and existing single family, multifamily, 

or manufactured housing, where applicable) was considered in the economic analysis. 

5.3.3.2 Commercial Technology

More than 150 commercial DSM measures within five programs were identified for program 

economic screening. These measures provide energy savings through:

 compliance with state standards and codes;

 increased energy efficiency for electric equipment;

 electric space cooling and heating equipment;

 electric lighting;

 electric water heating; and

 heating and cooling savings resulting from improvements to the building’s thermal shell.

In addition to specific measures, the building type (the type of customer operation, such as 

schools and offices, where applicable) was considered along with the construction type (new, 

existing or both, where applicable) when conducting the economic analysis. 
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5.3.3.3 Industrial Technology

A total of six custom industrial DSM measure categories within one custom program were 

identified for economic screening in the Advocacy and Aggressive Sensitivity Cases. No 

industrial programs are included in the Company’s recommended Proposed Case. These 

measures provide energy savings through:

 electric space cooling and heating equipment;

 electric lighting;

 motors;

 compressed air;

 industrial process equipment; and

 retro-commissioning.

5.3.4 Economic Screening

Energy consumption and savings were calculated for all programs that were passed to the 

economic screening. Two main methods were used to calculate the energy consumption and 

savings potential for each measure.

The energy usage characteristics for weather-sensitive HVAC and thermal shell measures were 

calculated using an engineering simulation model (“EnerSim”). EnerSim is an hourly building 

energy simulation model used to predict energy consumption in buildings based on construction 

characteristics, insulation, occupancy, orientation, local weather, etc. EnerSim was used to 

generate all energy usage profiles for weather-sensitive end-uses examined in both residential 

and non-residential measures. EnerSim has been certified and approved by the U.S. Department 

of Energy (“DOE”) and is listed on their website as “Qualified Software.” Energy usage for 

non-weather-sensitive end-uses was calculated using the EnerSim program, from secondary 

sources listed above, or from other end-use specific calculations.

Each potential end-use measure that was passed to the economic screening was then evaluated in 

an economic analysis model to determine its benefits and costs. The Company used PRICEM, 

which is an economic analysis tool maintained by SCS, for a portion of this analysis. PRICEM 
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produces estimates of the avoided utility costs and lost revenues over the useful life of the enduse equipment. Utility avoided costs include estimates of the supply-side capacity and energy 

costs that can be avoided by each measure and savings from generation, transmission, 

distribution, fuel, environmental, and other costs. 

The following industry-standard DSM cost-effectiveness tests were calculated for each measure 

(and subsequent programs): the PT, the RIM test, the TRC test, the PACT, and the SCT. 

Additionally, the Cost of Saved Energy (“CSE”), also referred to as Levelized Cost per annual 

kWh saved, is provided for each of the programs. The CSE is the total cost per kWh of realizing 

the efficiency improvement. CSE is determined by dividing levelized program costs by the 

annual energy savings, as shown in the following equation. Levelized program costs are 

calculated using a Capital Recovery Factor (“CRF”), which incorporates the number of years that 

the energy savings persist, and an annual discount rate. 

CSE Equation.

A compilation of the economic screening of DSM measures that passed the qualitative screening 

is included in Technical Appendix 2. 

5.4 DEMAND-SIDE PROGRAM DEVELOPMENT 

5.4.1 Demand-Side Resource Policy 

In the 2004 IRP, the Commission directed that proposed DSM plans should minimize upward 

pressure on rates (negative RIM results) and maximize economic efficiency (positive TRC 

results). Additionally, the Commission directed that the cost/benefit analysis results of each 

initiative should use all three tests (PT, RIM and TRC test) and should balance economic 

efficiency (TRC benefits) and fairness and equity (RIM benefits/cost). This Commission policy 

was affirmed in the 2007 and 2010 IRPs. The Company utilized this same philosophy in 

analyzing the programs for the 2013 IRP. 
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This IRP adheres with the Nine-Step process for developing the 2013 IRP approved by the 

Commission in July 2010 as part of the 2010 IRP Final Order.

5.4.2 10-Year DSM Program Plans

The Company has developed ten-year program plans outlining the implementation details behind 

each individual program included in the recommended Proposed Case. Each of the energy 

efficiency program plans are provided in the 2013 DSM Application.

Included in each program plan are the following details:

 Program Summary – outlines the goals of the program and presents a logic model to 

graphically represent the relationships between activities and outcomes for the individual 

programs.

 Program Structure – outlines participant eligibility, home or facility eligibility, and 

specific measures and incentives where appropriate.

 Program Implementation – outlines the target market, key market players, as well as 

marketing and outreach plans.

 Program Operation – outlines the customer participation process and program 

administrative procedures. 

 Program Evaluation – outlines the performance metrics, expected program budget, costeffectiveness expectations, as well as plans to develop an independent third-party 

evaluation plan after programs are approved.

5.5 REGULATORY TREATMENT OF DSM PROGRAM COSTS AND THE 

ADDITIONAL SUM

Georgia Power is requesting the continued collection of costs for all approved and certified DSM 

programs and activities through the existing Residential and Commercial DSM tariffs. Georgia 

Power is also requesting the continued collection of the Additional Sum approved by the 

Commission for certified DSM programs through these tariffs. These tariffs will be filed as part 

of the Company’s 2013 base rate case and would be implemented with any approved change of 

rates on January 1, 2014. 
5-71

5.6 SUMMARY OF DSM CASES

5.6.1 Proposed Case – Georgia Power Recommended Case

The energy efficiency programs in Georgia Power’s recommended Proposed Case for the 2013 

IRP achieve an average of almost $187 million (NPV over the life of the measures) in TRC 

benefits while putting upward pressure on rates of almost $82 million (NPV over the life of the 

measures) annually over years 2014 - 2016. The Company is concerned that these results are not 

striking the balance needed when considering energy efficiency programs, but recommends 

continuing the energy efficiency programs approved in the 2010 DSM Certification filing at the 

projected increased market participation levels. The Company’s recommendation to continue the 

programs at this time is based on the desire to minimize market disruption, to continue meeting 

customers’ expectations, and to maintain positive relationships with vendors performing 

qualified program improvements. The Company is also seeking to certify a Small Business 

program targeted toward a hard to reach customer sector. The Company plans to monitor 

program costs and economics during 2014 - 2016 and will be prepared to modify or discontinue 

programs if significant upward pressure on rates continues.

The Company’s DSM portfolio included in the 2013 IRP consists of currently certified 

programs, modified based on data gathered in the implementation phase and input from the 

DSMWG and the independent third party evaluation. The portfolio also includes a new Small 

Business program. If the Proposed Case is approved, Georgia Power will continue to enhance 

these programs as more information becomes available relative to market penetration and 

customer feedback through an ongoing evaluation process. Georgia Power will keep the 

Commission fully informed of potential changes to program design.

The Company’s Proposed Case summary economics are provided in the DSM Program 

Documentation section of Technical Appendix Volume 2. As part of the Nine-Step process, the 

Company agreed to calculate the generation avoided costs for its DSM change case using its 

system tool. The avoided generation costs for the Company’s proposed case from the system 

tool were not significantly different than the avoided generation costs obtained from PRICEM. 

Also, the avoided generation costs for the Advocacy and Aggressive Sensitivity Cases from the 
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system tool were not significantly different than the avoided generation costs obtained from 

PRICEM.

5.6.2 DSMWG Advocacy Sensitivity Case – All Program Concepts Identified with 

DSMWG Subgroup 

The DSMWG Advocacy Sensitivity Case was developed as a sensitivity case to the Company’s 

recommended DSM plan and is based on requests made by certain members of the DSMWG. 

Georgia Power presents the results of this case for informational purposes. Georgia Power does 

not recommend approval of the DSMWG Advocacy Sensitivity Case.

If the DSMWG Advocacy Sensitivity Case is implemented, the portfolio would put additional 

upward pressure on rates of approximately $461 million (NPV over the life of the measures) on 

average annually for years 2014 - 2016, almost six times higher than the Company’s 

recommended Proposed Case, while only increasing the economic efficiency (or TRC benefits) 

by about two and a half times. Over the life of all programs within this sensitivity case, rates 

would increase on average by about $613 million annually (NPV over the life of the measures) 

relative to the supply-side option. 

The DSMWG Advocacy Sensitivity Case summary economics are provided in the DSM 

Program Documentation section of Technical Appendix Volume 2.

5.6.3 Aggressive Sensitivity Case

The Aggressive Sensitivity Case was developed to represent an aggressive DSM sensitivity and 

was developed with input from the DSMWG, as outlined in the Nine-Step process. Georgia 

Power does not recommend approval of the Aggressive Sensitivity Case.

The Aggressive Sensitivity Case serves as a reference point to estimate the maximum achievable 

potential for increased energy efficiency and the impacts of such aggressive adoption of DSM. 

This increased energy efficiency comes at high cost to customers. The higher impacts from the 

Aggressive Sensitivity Case ultimately result in an average annual rate impact of more than $650 

million (NPV over the life of the measures) over the alternative supply-side resource plan for 

years 2014 - 2016, about eight times higher than the Company’s recommended Proposed Case, 
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while only increasing the economic efficiency (or TRC benefits) by about three and half times. 

Over the life of all programs within this sensitivity case, rates would increase on average by 

almost $861 million annually (NPV over the life of the measures) relative to the supply-side 

option. 

The Aggressive Sensitivity Case summary economics are provided in the DSM Program 

Documentation section of Technical Appendix Volume 2.
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6 – SUPPLY-SIDE PLAN
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SECTION 6 - SUPPLY-SIDE PLAN

6.1 OVERVIEW

The supply-side benchmark planning process consists of the following steps:

 Assessing options at existing generation facilities;

 Evaluating power purchases;

 Assessing current and new electric generation technologies that may be available when 

new capacity is needed;

 Selecting the least-cost mix of capacity to develop the plan and the benchmark plan; and

 Evaluating the benchmark plan across a range of changing assumptions to assess risk, 

flexibility, and other considerations.

The benchmark plan is used throughout the IRP process, and cost-effective demand-side options 

are integrated with the benchmark plan to create the IRP. The IRP is the basis for evaluations of 

resource options until the next plan is completed.

6.2 EXISTING GENERATING PLANT OPTIONS

The 2013 IRP contains a supply-side plan that reflects the Company’s decisions for transitioning 

its generation fleet to best meet the requirements of existing and potential environmental rules 

and regulations, most significantly, the final MATS rule. Encompassing previous actions and 

decisions resulting from the IRP planning process overseen by the Commission, as well as the 

Company’s requested actions in this 2013 IRP filing, the supply-side plan reflects an efficient 

and diverse fleet of resources. Further detail regarding existing and committed units is located in 

the Resource Ledger in Technical Appendix Volume 1.

6.2.1 Previous Resource Commitments 

The supply-side plan reflects previous decisions and actions resulting from the IRP planning 

process, including the retirements of Plant McDonough-Atkinson Units 1 and 2, Plant Mitchell 

Unit 4C, and Plant Branch Units 1 and 2. The plan also includes the addition of resources, most 

notably the two new nuclear units at Plant Vogtle Units 3 and 4, the three new CC units at Plant 
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McDonough-Atkinson Units 4-6, capacity planned and procured for the Company’s Large Scale 

Solar program and the GPASI, and the purchase of 998 MW of natural gas fired capacity and 

energy from West Georgia, Dahlberg and Harris and associative Proxy Qualifying Facilities’ 

(“QFs”) capacity resulting from the 2015 RFP.

6.2.2 Installation of Environmental Controls for Plant Bowen Units 1-4, Plant 

Wansley Units 1 and 2, Plant Scherer Units 1-3 and Plant Hammond Units 1-

4 to Allow for Continued Operation

An important aspect of the supply-side plan is the continued operation of coal-fired generation 

through the application of further environmental controls, most notably those required for MATS 

compliance. As described above and as detailed in Sections 1.6.1, 1.6.4, 1.6.8, and 1.6.9 in the 

Unit Retirement Study and in the Environmental Compliance Strategy contained in Technical 

Appendix Volume 2, the Company has developed a MATS compliance strategy for Plant Bowen 

Units 1-4, Plant Wansley Units 1 and 2, Plant Scherer Units 1-3, and Plant Hammond Units 1-4. 

The Company’s analysis of continued operations of these resources results in a net benefit to 

customers and will result in these valuable assets continuing to economically serve customers’ 

needs, while maintaining a significant role for coal in the Company’s generation fleet.

6.2.3 Switching Primary Fuels at Plant Mitchell Unit 3, Plant Yates Units 6 and 7, 

Plant McIntosh Unit 1, and Plant Gaston Units 1-4 to Allow for Continued 

Operation

The supply-side plan also includes continued operations at Plant Mitchell Unit 3, Plant Yates 

Units 6 and 7, Plant McIntosh Unit 1, and Plant Gaston Units 1-4. As discussed above, the 

MATS compliance strategies for these plants are different than for Plants Bowen, Wansley, 

Scherer and Hammond. While Plants Bowen, Wansley, Scherer, and Hammond will achieve 

MATS compliance through varying applications of baghouses, and MATS additives, the 

compliance strategies for the units discussed below rely heavily upon leveraging opportunities 

presented by switching primary fuels.

Plant Mitchell Unit 3 reflects the conversion to a biomass generating unit previously approved by 

the Commission to allow for continued future operation. The Company provided updates on the 

conversion project through the Commission’s construction monitoring process and continues to 

evaluate the economics of the conversion; therefore, the unit is assumed to be unavailable in 
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2015 and 2016 and then available as a biomass generating unit in 2017 and beyond in this 2013 

IRP. For further details regarding Plant Mitchell Unit 3, please see Section 10.5.2. 

Plant Yates Units 6 and 7 will continue to operate by switching to natural gas as the primary fuel, 

as MATS is not applicable to natural gas-fired units. Details regarding the assumptions for the 

compliance strategy are contained in Section 1.6.11 in the Unit Retirement Study contained in 

Technical Appendix Volume 2.

Plant McIntosh Unit 1 will continue operations by completing a fuel switch to PRB coal 

(pending a successful test burn and subsequent feasibility study in 2013) and the installation of 

activated carbon and dry sorbent injection technologies by an assumed date of April 2016. 

Assuming the project is completed after the MATS compliance date of April 15, 2015, a one 

year MATS extension would be requested from the EPD to ensure the unit can operate until the 

switch to PRB coal is complete. Details regarding the assumptions for the compliance strategy 

are contained in Section 1.6.6 in the Unit Retirement Study and in the Environmental 

Compliance Strategy contained in Technical Appendix Volume 2. 

Similar to Plant Yates 6 and 7, Plant Gaston Units 1-4 will continue operations by switching to 

natural gas as the primary fuel. Details regarding the assumptions for the compliance strategy 

are contained in Section 1.6.3 in the Unit Retirement Study contained in Technical Appendix 

Volume 2. Completion of the gas lateral and unit modifications for Plant Gaston Units 1-4 is 

scheduled for 2015 to meet the MATS compliance timeline; however, the project schedule is 

compressed. An extension to the MATS compliance date may be required to ensure the units 

operate in compliance while on coal if the current project schedule cannot be met. 

6.2.4 Decertification of Plant Branch Units 3 and 4, Plant McManus Units 1 and 2, 

Plant Kraft Units 1-4, Plant Yates Units 1-5, Plant Boulevard Units 2 and 3, 

and Plant Bowen Unit 6

The supply-side plan reflects the retirements of Plant Branch Units 3 and 4, Plant Yates Units 1-

5, and Plant McManus Units 1 and 2 effective with the MATS compliance date. It also reflects 

the retirement of Plant Kraft Units 1-4 one year past the MATS compliance date to allow for 

necessary area transmission upgrades, the retirement of Plant Boulevard Units 2 and 3 effective 
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as of the date of the final order in this proceeding, and the retirement of Plant Bowen Unit 6 by 

April 16, 2013.

Details regarding the assumptions for the compliance strategies required for Plant Branch Units 3 

and 4, Plant McManus Units 1 and 2, Plant Kraft Units 1-4, and Plant Yates Units 1-5 are 

contained in Sections 1.6.2, 1.6.5, 1.6.7, and 1.6.10 in the Unit Retirement Study contained in 

Technical Appendix Volume 2. The results of the analyses show that it is not economic for 

customers for the Company to invest in these units to allow for continued operations.

Plant Boulevard Units 2 and 3 are two oil-fired CTs that have recently experienced significant 

equipment failures that would be costly to repair. Following a failure of the two units in July and 

November, respectively, a camera probe of the units was performed to determine what parts 

would need to be repaired or replaced. Through this effort, it was revealed that the compressor 

rotor blades were damaged on Unit 2 and the repair was estimated to cost $1.95 million. For 

Unit 3, a camera probe also revealed damage to the compressor on that unit and a repair was 

estimated at $1.75 million. In Section 1.6.12 in the Unit Retirement Study contained in 

Technical Appendix Volume 2, the estimated cost of repairs for Plant Boulevard Units 2 and 3, 

as well as the annual maintenance capital and O&M budgets for the units, were included as the 

costs of the unit. Based on the cost of repair, the age of the units, and the potential for additional 

part failure, it is not considered economic to repair and continue operating these units.

Plant Bowen Unit 6 is a 32 MW oil-fired CT that can only operate during the non-summer 

months due to ozone nonattainment requirements in the area. The economics of the unit were 

evaluated and are included in Section 1.6.13 in the Unit Retirement Study contained in Technical 

Appendix Volume 2. Based on this evaluation, it is uneconomic to continue operating this unit. 

Several options were explored for the unit, however, to help facilitate baghouse construction 

occurring at Plant Bowen Units 3 and 4, and the Company determined that it is most optimal for 

this unit to be removed no later than June 1, 2013.

Additionally, early decertification is being sought for this unit in order to take advantage of an 

agreement in place to sell the unit. In order to allow the buyer sufficient time to remove the unit 

before June 1, 2013, decertification would need to be granted by April 16, 2013. 
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6.2.5 Blackstart Resources and Transmission System Restoration Plan

For transmission reliability purposes, certain generating units are designated as “Blackstart 

Resources”. Blackstart Resources are defined, per NERC reliability standards, as “a generating 

unit(s) and its associated set of equipment which has the ability to be started without support 

from the System or is designed to remain energized without connection to the remainder of the 

System, with the ability to energize a bus, meeting the Transmission Operator’s restoration plan 

needs for real and reactive power capability, frequency and voltage control, and that has been 

included in the Transmission Operator’s restoration plan”. A review and assessment of 

Blackstart Resources and the Company’s Transmission Operator system restoration plan 

continues in conjunction with unit retirement studies. System restoration plans will continue to 

be updated annually at a minimum or as required due to changes in the future mix of generating 

assets. 

6.3 SUPPLY-SIDE OPTIONS

Based on current projections and reflecting reserve sharing for the System, the Company is 

projected to have adequate capacity reserves through 2022 and, thus, there is no plan in this IRP 

to add capacity within the next three years. As discussed in Section 6.2, the Company has 

developed plans for the retrofitting and transitioning of its generation fleet to best meet the 

requirements of existing and potential environmental rules and regulations including, most 

significantly, the final MATS rule.

6.4 NEW GENERATING TECHNOLOGIES

The System continually evaluates conventional and emerging generating technologies as a 

starting point in developing a base supply-side plan. The objective is to assess their cost, status 

of development, cost uncertainties, environmental acceptability, fuel availability, construction 

lead times, and other factors. 

The evaluation process: 

 Identifies and reviews all conventional and new supply-side generation technologies;
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 Performs a preliminary technology screening analysis based on technical, economic, 

environmental, and resource availability information;

 Performs a more detailed technology screening analysis of the options that passed the 

preliminary screening, which includes a busbar economic comparison of the candidate 

technologies;

 Projects the future cost and performance of the selected supply-side alternatives; and

 Identifies the technologies to be recommended for inclusion in the resource mix studies.

6.4.1 Preliminary Screening

The 2013 technology screening process identified 39 technologies for strategic assessment. 

They are listed in Section 14, Attachment 14.2 and Table 14.2.1. The strategic or qualitative 

assessment considered the stage of development of the technology, fuel availability, 

environmental impact, financial requirements, cost uncertainties, construction lead-time, and 

operating characteristics.

Many technologies from the initial list did not pass the preliminary screening due to their limited 

applicability to the territory (e.g., Ocean Thermal Generation) or their early stage of development 

(e.g., magnetohydrodynamics). Twenty-two technologies were carried forward for more detailed 

analysis (refer to Section 14, Attachment 14.2 and Table 14.2.3). See Section 10 for discussion 

regarding renewable generation options.

6.4.2 Detailed Screening

In order to pass through the second screening, a supply-side option must have desirable 

economic characteristics, as well as desirable environmental and other non-price characteristics.

To be economically attractive, an option must be among the lowest-cost options across a range of 

capacity factors. A busbar cost screening analysis is the common industry method used to 

determine the cost of operating a unit over a range of capacity factors. Busbar models combine 

the capital and operating costs of generating units so that the costs of operating units can be 

compared under various hours of annual operation. Also, busbar models provide an indication of 
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the economic viability of one technology compared with others. Busbar models are very useful 

in screening evaluations for generation technology options.

All data assumptions are shown in Table 6.4.2 in the IRP Main Document Reference Tables 

section of Technical Appendix Volume 1. A capital cost comparison and busbar curves are 

shown in Figures 6.4.2.1 and 6.4.2.2, respectively, in the IRP Main Document Reference Tables

section of Technical Appendix Volume 1.

Even though a technology may not be the absolute lowest-cost option, it may be a desirable 

alternative due to qualitative features, such as stage of development, ease of siting, modularity, 

short construction lead time, flexible operating characteristics, fuel diversity, or anticipated 

improvements that favorably impact the economics of the technology. These attributes are also 

considered in the detailed screening.

6.4.3 Nuclear Generation

Nuclear generation is included as a generating unit option in this IRP. The 2013 Generation 

Technology Data Book, included in Technical Appendix 1, provides the capital cost for prelicensed nuclear generation. 

6.4.4 Generation Mix Candidate Selections

The detailed economic results are used to determine likely candidates as representative capacity 

options in the base case resource mix studies. The base case technologies recommended include: 

 CT, peaking;

 CC – “G”, base load/intermediate;

 CC – “G”, with carbon capture and sequestration (CCS), base load/intermediate;

 Nuclear, base load; and

 Coal with carbon capture and sequestration (CCS), base load. 

6.5 SUPPLY-SIDE PLAN

To develop a supply-side plan, the technologies that passed the detailed screening are further 

evaluated using the PROVIEWTM computer model to arrive at a benchmark plan. The key input 
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assumptions are generating unit characteristics, fuel costs, reliability needs, financial costs and 

escalation rates. A summary of the PROVIEWTM model is in Section 14. 

6.5.1 Base Case Assumptions

Generating Unit Costs — The types of generating units used in developing the benchmark plan 

were coal with CCS and nuclear, CC (both with and without CCS) and peaking CT. 

Fuel Costs — In the optimization process, the primary fuels used in the candidate units of the 

optimization are nuclear, coal, oil, and gas. Figure 3.7.1 in the Mix Study in Technical Appendix 

Volume 1 shows projections of nominal delivered costs of coal, nuclear, oil, and natural gas 

based on heat content. 

Reliability Needs — The supply-side plan is currently developed to meet a System planning 

target reserve margin of 15 percent. This target was developed using a combination of economic 

studies, electric industry experience, and operator input. The economic analysis compares 

emergency purchase cost and customers’ value of service [based on EUE cost] with the cost of 

adding capacity to avoid outages. 

Financial Cost and Escalation — Long-term debt and common and preferred stock are issued 

to finance the construction of generating units. The returns demanded by the investment 

community are affected by perceptions of the inflation rate and business risks. The returns 

demanded by the investment community and the income tax rates affect the carrying cost of the 

investment, which can in turn affect the mix of capacity.

The Moody’s Analytics forecast is the basis of the financing and inflation cost estimates used in 

the planning process. For the mix analysis, an internally-developed average set of costs 

escalations was used. Discount analysis using the weighted average cost of capital is applied to 

place more emphasis on the near term. (More information on this topic is available in the Mix 

Study report in Technical Appendix Volume 1.) The financial parameters used in the mix 

process are also shown in the Mix Study in Technical Appendix Volume 1.
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6.5.2 Benchmark Plan Results

The optimization process utilizes the PROVIEWTM module of the production cost Strategist® 

model and determines the proper mix of capacity to serve a designated load. The results of this 

analysis indicate the proposed capacity additions. The capacity additions identified within this 

analysis serve as a guide for the type of capacity needed in a particular timeframe with the given 

assumptions. As prescribed by the Commission’s rules and orders, a combination of self-owned 

generation and a competitive bidding process will be used for determining how the capacity 

needs are to be met. 

The optimization process is essentially a trade-off between fixed costs and variable operating 

costs for the various generating unit options. Figure 6.5.2.1 in the IRP Main Document 

Reference Tables section of Technical Appendix Volume 1 depicts changes in energy mix by 

fuel source for the 2013–2032 planning period. As energy usage increases and no new coalfueled generating units are added, the amount of energy supplied by oil and natural gas will 

increase. Figure 6.5.2.2 in the IRP Main Document Reference Tables section of Technical 

Appendix Volume 1 shows the portion of annual energy needs met by nuclear, coal and hydro 

units over the planning period 2013 - 2032. Table 6.5.2.1 in the same section of Technical 

Appendix Volume 1 shows the System Benchmark Capacity Plan.

6.5.3 Reference Case Sensitivities

There are four major reasons to test the benchmark plan under different assumptions:

 To determine how well the plan will meet customer needs under a variety of different 

future outcomes;

 To determine if the plan should be altered to make it more flexible in meeting unforeseen 

changes;

 To build knowledge and intuition concerning the effect that different assumptions will 

have on the supply-side plan; and

 To identify and focus attention on additional studies to be performed.
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The following sensitivities were performed in the development of the Company’s IRP. These 

sensitivities are analyzed in detail in the System Mix Study found in Technical Appendix 

Volume 1.

 Forecast of load:

o Sensitivity 1 evaluates zero load growth from 2013 levels.

o Sensitivities 2 and 3 evaluate higher and lower load growth.

 In-service dates of supply and demand resources:

o Sensitivities 4 and 5 evaluate levels of demand-side options.

o Sensitivities 12 through 21 evaluate the impacts of varying in-service dates and 

amounts of supply and demand resources through the scenario planning cases. In 

addition to separate fuel price forecasts and estimates of carbon prices, sensitivity 

cases 13 through 21 produce separate evaluations of the impacts on the load and 

energy forecasts, which include effects from demand-side programs, and new 

supply-side resources.

 Unit availability:

o Sensitivities 6 and 7 evaluate lower and higher forced outage rates.

 Fuel prices:

o Sensitivities 13 through 21 evaluate the impacts of fuel prices through the 

scenario planning cases which have three separate fuel price forecasts combined 

with varying estimates of carbon prices to produce separate evaluations of the 

impacts on the load and energy forecasts, which include effects from demand-side 

programs, and new supply-side resources. 

 Inflation in plant construction costs and costs of capital:

o Sensitivity 8 incorporates a higher cost of capital assumption.

o Sensitivities 9 and 10 analyze the impacts of doubling and tripling the 

construction cost escalation rates, respectively.

 Availability and costs of purchased power:

o Sensitivity 11 evaluates the impacts of the availability and costs of purchased 

power.

 Pending federal or state legislation or regulation:
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o Sensitivities 13 through 21 evaluate the impacts of pending legislation or 

regulation through the scenario planning cases. The impacts of pending 

legislation or regulation can be analyzed by varying estimates of carbon and fuel 

prices. The scenario planning cases produce separate evaluations of these impacts 

on the load and energy forecasts, demand-side programs, unit retirements, and 

new supply-side resources.

 Rate impact analysis: 

o All of the sensitivities analyze the impacts on rates of the varying changes in 

assumptions. The rate impacts are included in the Financial Review in Technical 

Appendix Volume 2. 

The Mix Study in Technical Appendix Volume 1 and Financial Review in Technical Appendix 

Volume 2 provide descriptions of these analyses and the impacts of each sensitivity analysis on:

 The timing, amounts, and types of new capacity needed to meet customers’ needs;

 The costs associated with meeting the load growth on the system; and

 System marginal costs.
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7 – INTEGRATION OF 

DEMAND-SIDE 

PROGRAMS INTO 

THE BENCHMARK 

SUPPLY-SIDE PLAN
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SECTION 7 - INTEGRATION OF DEMAND-SIDE PROGRAMS INTO THE 

BENCHMARK SUPPLY-SIDE PLAN

7.1 INTRODUCTION

In the integration step, those demand-side programs resulting from the DSM evaluation are 

integrated with the appropriate benchmark supply plan using the Strategist®/PROVIEWTM 

model. This method ensures a cost-effective mix of demand-side and supply-side resources are 

selected, while acknowledging the limits of available demand-side resources.

7.2 DISTRIBUTING CAPACITY AMONG THE OPERATING COMPANIES

In order to make the full benefits of coordinated planning available to the System’s operating 

companies, the mix optimization process is performed for all of the system operating companies. 

For long-range planning purposes, the generating unit resources resulting from the mix process 

must then be distributed or allocated among the system operating companies based on their 

particular needs and current resources. This planned distribution is performed through an 

analysis of each company’s existing resources and energy needs. The actual resource selection is 

based on the specific operating company needs instead of the planning assumptions. As the time 

for commitment to new capacity approaches, additional detailed studies are performed to identify

the resources for meeting specific operating company requirements. The decision to acquire new 

generating capacity or demand-side resources will be made by the operating company based on 

studies of customer needs and the operational, cost, and financial assumptions specific to the 

operating company and the options available.

See the Mix Study in Technical Appendix Volume 1 for additional details.
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8 – INTEGRATED 

RESOURCE PLAN
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SECTION 8 - INTEGRATED RESOURCE PLAN

8.1 OVERVIEW

The 2013 IRP projects that the demand for electricity by the Company’s customers will continue 

to grow. Georgia Power must acquire a significant amount of new resources by 2032 in order to 

reliably serve these new requirements and replace units retired from generating service. The IRP 

recommends a cost-effective mix of supply-side and demand-side capacity resources to meet 

future requirements.

8.2 INTEGRATED RESOURCE PLAN 

For the period of 2013 – 2022, reflecting reserve sharing for the System, Georgia Power is 

projected to have sufficient resources to meet customers’ needs given the resources approved by 

the Commission in the 2011 IRP Update and other previous filings, as described in preceding 

sections. For the year 2023, the Company has a capacity need based on 10 years of projected 

load growth, and the reduction in system reserves due to increased system loads and the 

expiration of PPAs currently available to the system. Without reserve sharing, the Company’s 

first year of capacity need is 2021.

The long-term plan for each of the scenario cases varies depending on the assumptions for that 

case. The Unit Retirement studies of the existing fleet of generating facilities results in the 

development of an expected MATS compliance plan for existing units, a plan which is shared 

across all scenarios and sensitivities. For some of the scenario cases, a mix of gas technologies 

(CTs and CCs) was selected through the planning period when capacity was needed to maintain 

reliability, meet growing customer needs, or for fuel-cost savings. In other scenario cases, 

nuclear was selected in addition to certain gas-fired generation, including CCs with CCS, during 

the planning period when capacity was needed to maintain reliability, meet growing customer 

needs, or for fuel-cost savings.

The IRP utilizes demand-side resources and acquires the proper mix of capacity through power 

purchases or self-owned resources (i.e., self-built and/or acquired from existing assets) in 

sufficient amounts to meet minimum System reliability criteria. The IRP (as shown in Figure 8.2 

and Table 8.2 in the IRP Main Document Reference Tables section of Technical Appendix 
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Volume 1) shows the resource needs for the years 2013 – 2032 based on current environmental 

requirements and other base case assumptions. When Georgia Power acquires its resource needs 

through the RFP process, the actual generation technology purchased is dependent on what the 

market bids to the Company.

8.3 PLAN REVIEW BASED ON OTHER PLANNING OBJECTIVES

The IRP was reviewed based on the additional planning objectives listed below.

 Flexibility — Can the plan be altered if the future is different than expected?

Yes. In the near term, the IRP relies on demand-side programs, pricing tariffs, and shortterm supply-side purchases when appropriate. Natural gas-fueled capacity proved to be 

the next supply-side resource needed under the analyses performed in the base case IRP 

while nuclear is selected in certain scenario planning cases with carbon prices. The 

relatively short lead time (four years or less) required for a simple cycle CT and the 

utilization of short-term purchases will provide the flexibility to meet any uncertainties 

that may arise. 

 Reliability — Does the plan provide reliable service for all customers?

Yes. The IRP holds System reliability at a level that balances the cost of outages and the 

cost of new generating capacity.

 Long-Term Viability — Will the plan meet customer needs over the long term?

Yes. The IRP adequately provides for needed capacity resources in the future and 

minimizes the need for rate increases. There is flexibility to alter the plan as needed. 

Customers have the opportunity to participate in the demand-side program or pricing 

options that fit their individual needs. The IRP is a viable long-term plan under the 

current regulatory and operating environment.

 Environmental — Does the plan ensure compliance with environmental regulations?
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Yes. In addition to complying with all existing laws and regulations, the Company 

reviews and assesses pending rules, regulations and legislation in regard to environmental 

issues that may impact Georgia Power and Southern Company. The Company’s 

Environmental Compliance Strategy document is included in Technical Appendix 

Volume 2. Additional environmental sensitivities and their impact on the generation mix 

analysis are also included in the Mix Study in Technical Appendix Volume 1 and the 

Financial Review in Technical Appendix Volume 2. 

 Risk — Does the plan appropriately mitigate the risk of future changes in conditions?

Yes. There is a risk that the load growth will be more or less than expected, and that the 

demand-side programs may not be well-received or provide the projected load reductions. 

There also is risk that there will be more interest in DSM than currently experienced, 

decreasing the need for new capacity acquisitions. Finally, there is risk associated with 

uncertainty regarding expected environmental rulemakings and their potential impact on 

retirement of some existing resources. The plan balances this risk against cost to 

customers. The Financial Review included in Technical Appendix Volume 2 provides 

additional information regarding the business and financial risks associated with the IRP.

 Shareholder Value — Will the plan provide shareholders with the opportunity to earn a 

fair return on their investment?

Yes. The IRP process provides for a full review of the need to add new generation 

resources and the certification of resources chosen to fill those needs. This process 

provides shareholders with a greater level of certainty that their investments in these 

certified resources will result in the ability to earn a fair and reasonable return.
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9 – SUMMARY OF 

TRANSMISSION PLAN
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SECTION 9 - SUMMARY OF TRANSMISSION PLAN

9.1 TRANSMISSION PLAN

This IRP includes the Company’s ten-year transmission plan, which identifies the transmission 

improvements needed (based upon current planning assumptions) to maintain a strong and 

reliable transmission system. In addition, it contains any necessary transmission improvements 

related to the Company’s compliance strategy, outlined in this document, developed as a result of 

the EPA’s MATS rule. Along with the ten-year plan, Georgia Power has included a 

comprehensive and detailed bulk transmission plan of the Georgia Integrated Transmission 

System. 

9.2 TRANSMISSION PLANNING PRINCIPLES

The purpose of the transmission planning principles is to provide an overview of the standards 

and criteria that are used for transmission expansion and upgrade proposals. These principles are 

designed to help ensure the coordinated development of a reliable, efficient, and economical 

electric power system for the transmission of electricity for the long-term benefit of the 

transmission users. These principles also recognize that planning should be proactive in order to 

ensure timely system adjustments, upgrades, and expansions. The principles that apply to 

Georgia Power’s transmission planning are as follows:

 Identify and recommend projects that are consistent with the Guidelines for Planning the 

Georgia Integrated Transmission System (“ITS”) and the Guidelines for Planning the 

Southern Company Electric Transmission System;

 Identify and recommend projects that are consistent with the NERC Planning Standards 

and the SERC Supplement to the NERC Planning Standards;

 Minimize costs associated with the ITS expansion, giving appropriate consideration to 

system reliability;

 Identify projects with sufficient lead-time to provide for the timely land acquisition and 

construction of new transmission facilities;

 Recommend budget expenditures that recognize the financial capabilities and limitations 

of Georgia Power;
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 Coordinate transmission system plans with the plans developed by the Transmission and 

Distribution (“T&D”) Area and Distribution Planning groups, the T&D Planning Section, 

Distribution, Engineering, Land, Operations, Protection, other ITS members, other 

Company departments, and the regions surrounding the Southeast to seek their active 

involvement in the project development and planning process;

 Coordinate transmission system plans with all ITS participants in an effort to enhance 

reliability and minimize associated costs; and

 Maintain adequate interconnections with neighboring utilities.

These principles provide guidance to planners and/or planning authorities that are called upon to 

explore existing issues and any future problems encountered in the transmission planning 

process.

9.3 10 YEAR TRANSMISSION PLAN

Georgia Power is a member of the ITS, which consists of the physical equipment necessary to 

transmit power from the generating plants and interconnection points to the local area 

distribution centers in most of Georgia. The ITS is jointly owned by Georgia Power, Georgia 

Transmission Corporation, MEAG Power, and Dalton Utilities. Transmission planning 

embodies investment decisions required to maintain the ITS so that it can reliably and 

economically meet the power needs of the public. Justifications used in any such decisions are 

based on technical and economic evaluations of options that may be implemented to meet these 

needs.

Transmission Planning-East (“TP-East”) of the SCS Transmission Planning department is 

responsible for planning the transmission system for Georgia Power. TP-East, in conjunction 

with the other participants in the ITS and the interconnected neighboring utilities, develops a 

model of the transmission system for each year for ten years into the future. These planning 

models are used to identify transmission problems based on NERC and ITS planning guidelines 

and to evaluate alternative cost-effective solutions to the problems. Investment decisions must 

accommodate the fact that future load levels and generation plans are uncertain. This ensures 

that the planning process does not have to start anew each time a change is made.
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All Transmission Planning information is provided in Technical Appendix Volume 3 per the 

Commission’s 2007 IRP Order and the amended rules adopted by the Commission in Docket No. 

25981. Additional Transmission Planning information required per Docket No. 31081 is 

available in Technical Appendix Volume 3.
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10 – RENEWABLE 

RESOURCES 
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SECTION 10 - RENEWABLE RESOURCES

10.1 RENEWABLE RESOURCES OVERVIEW

Throughout its history, Georgia Power has diligently and resourcefully pursued cost-effective 

opportunities to cultivate renewable generation in Georgia in a responsible manner. As a result 

of the collaborative efforts of Georgia Power, the Commission, and the renewable energy 

community, there are currently 11.6 MW of solar generation (with another 50 MW under 

contract to commence service in the future), 142 MW of biomass generation including landfill 

methane gas, and 1,088 MW of hydro generation serving customers. Combined, these resources 

provide enough electric capacity to power the peak needs of more than 257,000 homes. With the 

introduction of the GPASI, the total amount of solar energy under contract by Georgia Power is 

expected to be more than 270 MW by the end of 2014. In addition to procuring cost effective 

renewable resources, Georgia Power also supports research and demonstration of renewable and 

emerging technologies. In all of these efforts, the Company seeks to responsibly expand the fuel 

diversity of our supply mix through our commitment to cost effective renewable generation. 

10.2 GREEN ENERGY PROGRAM

Georgia Power seeks to provide electricity to customers from renewable generation sources that 

do not cause rates to increase as compared with other available generation options. To do this, 

the Company must develop or purchase energy from sources at a cost equal to or below current 

avoided cost. The Company monitors and participates in R&D to find renewable technologies 

that it can add to our energy portfolio as these technologies become economically feasible. For 

customers who are willing to voluntarily cover the additional cost of renewable generation when 

such costs exist, the Company offers the Green Energy Program. 

The Commission approved Georgia Power’s Green Energy Program (“Green Energy Program”) 

in 2003 in Docket No. 16573. This order approved both the Green Energy (“GE”) tariff for the 

sale of Green Energy and the Renewable and Non-Renewable Resources (“RNR”) tariff for the 

purchase of Green Energy. After the Company contracted with DeKalb County for the output 

from the Seminole Landfill generator, the Green Energy Program’s primary energy resource, the 

Company enrolled and began billing customers in 2006.
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Again in 2008, in Docket No. 16573, the Commission approved several modifications to the 

Green Energy Program including the following four options through which customers could 

purchase Green Energy:

 Standard Green Energy, with a price of $3.50 per 100 kWh block;

 Premium Green Energy, containing at least two percent solar content for $4.50 per block;

 A Special Events Purchase Option, allowing customers to purchase Green Energy for a 

single event; and

 The Large Volume Purchase Option, providing large quantities of Green Energy on a 

customer specific basis.

At the Commission’s request, the Company filed a petition for modification of the Green Energy 

Program on December 18, 2009 that included a 100 percent solar option priced at $12.00 per 100 

kWh block. Commission Staff proposed a 100 percent solar option at a price of $9.00 per 100 

kWh block. Subsequently, feedback from solar stakeholders indicated that a product with these 

prices would likely not find acceptance in the marketplace. As a result, on February 18, 2010, 

the Commission ordered the Company to revise the GE tariff and alter the Premium Green 

Energy product to include at least 50% of energy from solar resources. Finally on April 20, 

2010, in Docket No. 16573, the Commission approved a revised Green Energy tariff, GE-4, that 

increased the price of Premium Green Energy to $5.00 per 100 kWh. 

Following implementation of the Large Volume Purchase Option, the Green Energy Program 

experienced considerable growth in sales. Due to the increased interest, the Company needed to 

procure additional resources to supply the Program, and an RFP was issued for renewable energy 

to meet the growing customer demand. On March 22, 2010, the Company executed a PPA with 

WM Renewable Energy, LLC to purchase 100% of the renewable energy from a 6.4 MW landfill 

gas facility in Savannah.

The Company launched significant marketing efforts to raise participation levels in each of the 

four product options. Green Energy and solar information is readily accessible on the redesigned 

GeorgiaPower.com website. A YouTube video is available to explain the features and benefits 

of the Standard and Premium products and encourage participation. Other social media tools 

such as Facebook and Twitter raise awareness of the Green Energy Program. Also, the 
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Company has been successful in obtaining new Special Event contracts by partnering with its 

Key Account Management employees, who serve the Company’s largest customers. Some of 

the Green Energy Program Special Events include the Atlanta Botanical Garden’s “Garden 

Lights Holiday Nights” event, the Chick-fil-A Bowl, the Athens Clarke Classic Center’s 

Greenlife Expo and the Atlanta Hawks green season purchase. 

The Company has maintained a successful level of Large Volume sales. As of June 2012, five 

customers were purchasing more than 41 million kWh of Green Energy per year. The Company 

continues to work diligently to meet all reporting obligations set forth by the Commission and 

the Energy Information Administration. The Company also maintains Green-e

® certification and 

successfully meets the stringent requirements of the annual audit. In the fourth quarter of 2011, 

the Company implemented a Large Volume marketing campaign to proactively target over 60 

high potential customers with pricing offers to purchase Green Energy. Although none of these 

customers executed a contract, many large customers became familiar with options to purchase 

Green Energy. 

In summary, the Green Energy Program serves over 4,000 participants that voluntarily pay more 

to support energy generation from renewable resources. The Green Energy Program has 

stimulated the growth of renewable resources in Georgia and is directly responsible for 9.6 MW 

of landfill gas and 5.4 MW of solar generation. However, challenges lie ahead. The Green 

Energy Program is currently under-recovered due to low avoided energy costs and flattening 

sales. Furthermore, as a result of available tax credits, rebates, and other distributed generation 

purchase programs, some customers have chosen to install their own renewable resources rather 

than purchase through the Green Energy Program. The Company will continue to monitor these 

developments and work with the Commission and stakeholders to implement Green Energy 

Program improvements. 

10.2.1 Distributed Generation Energy Purchases

The RNR tariff was approved as part of the Green Energy Program in 2003. Georgia Power 

purchases a portion of its renewable energy from distributed generation resources through the 

RNR tariff. The tariff offers two metering options: bi-directional metering and single directional 

metering. Bi-directional metering allows customers to offset their usage and sell any excess 
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energy back to the Company at the Company’s avoided energy cost. Single directional metering 

allows customers to sell 100% of the output of their solar panels, plus any associated Renewable 

Energy Credits (“RECs”), to the Company at a premium price. 

Bi-Directional Metering: The RNR tariff provides a means for Georgia Power to comply with the 

Georgia Cogeneration and Distributed Generation Act of 2001 and allows for the purchase of 

this energy at avoided energy cost in compliance with the Commission’s final order in Docket 

No. 4822. 

Single Directional Metering: At the inception of the RNR tariff, a total capacity cap of 500 kW 

was established for purchases of energy from solar resources at premium pricing. On August 4, 

2009, the Commission, in Docket No. 16573, increased the capacity available for the premium 

solar price by 1,000 kW to a total of 1,500 kW. Despite these considerable increases in capacity, 

there continued to be a significant waiting list for single directional metering through the RNR 

tariff as customers sought the guaranteed premium pricing to help make their solar projects 

viable. 

As part of the 2010 IRP, the Company sought approval to raise the cap by an additional 1,000 

kW to 2,500 kW total. The Commission approved this request and also implemented a 

mechanism whereby the capacity cap would automatically increase with additional sales of 

Premium Green Energy. Under this method, sales of 219 additional blocks of Premium Green 

Energy would result in a 100 kW increase in the capacity cap of the RNR tariff. The Company 

was able to grow the sales of Premium Green Energy by converting the required monthly buythrough of Large Volume customers to Premium from Standard Green Energy. As a result, the 

Company increased the capacity cap of the RNR tariff by 400 kW to a total of 2,900 kW. The 

new total capacity cap was split, with 500 kW reserved for projects with a peak generating 

capacity of 25 kW or less and 2,400 kW reserved for applications of greater than 25 kW but not 

more than 100 kW. 

In September 2010, the Company proposed to modify the Green Energy Program by adding the 

Solar Purchase (“SP”) tariff and changing the RNR tariff. On December 31, 2010, the RNR 

tariff was closed for additions of energy purchased from solar photovoltaic resources at prices 

above avoided energy cost. Pursuant to Docket No. 16573, the Company continues to purchase 
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energy from solar resources through the single-directional metering option of the RNR tariff at 

the Solar Purchase Price—currently set at 17¢ per kWh. The RNR bi-directional metering 

option continues to exist for avoided energy purchases in compliance with the Commission’s 

final order in Docket No. 4822.

The new SP tariff allowed for an additional 1,500 kW of solar capacity to be purchased at the 

new Solar Purchase Price of 17¢ per kWh, which increased the Company’s total solar capacity at 

premium pricing to 4,400 kW. This new capacity was split by facility size, with 85 percent of 

the capacity for facilities greater than 25 kW but not more than 100 kW and 15 percent of the 

capacity for facilities 25 kW or smaller. In addition, the Company was approved to issue a Solar 

RFP through which it would purchase another 1,000 kW of capacity at a price of 15¢ per kWh or 

less.

Georgia Power issued the RFP on May 3, 2011. There were three bidders that submitted four 

bids, with Solar Design & Development, LLC (“SDD”) selected as the winning bidder. On 

December 8, 2011, the Company executed a contract for the purchase of solar energy and RECs 

from SDD. SDD designed, developed, and installed a solar PV generation facility consisting of 

approximately 4,255 solar panels located in Hannahs Mill, Georgia with a total capacity of 1 

MW of electric power. 

Georgia Power has executed additional contracts to fill the new SP tariff capacity and continues 

to maintain an extensive waiting list for this premium pricing.

10.2.2 Community Supported Projects and Capacity Exceptions

In the 2010 IRP, the Company proposed a methodology for accepting community sponsored 

solar projects in response to a large number of requests for this type of offering from solar 

developers. This method allows developers to solicit community support for solar projects and 

be granted an exemption to the SP capacity cap. The community supporters would need to 

purchase an additional 219 blocks of Premium Green Energy in order for a 100 kW solar project 

to be constructed. Currently, no developers or customers have participated in this program.
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10.3 OVERVIEW OF ADDITIONAL SOLAR INITIATIVES

Driven by an extended period of declining solar module and balance of system pricing, Georgia 

Power has received Commission approval to responsibly grow the solar portfolio for customers 

by 260 MW through the GPASI and LSS programs. These programs allow for procurement of 

distributed and utility scale solar projects in the state without inducing any incremental upward 

rate pressure on customers. In addition, the Company also continues to contract with solar 

projects as QFs at the Company’s avoided cost rate. Several of the QF solar projects as large as 

1.5 MW in size have been under contract since 2011. 

The following graph illustrates the expected cumulative contracted solar capacity for Georgia 

Power through 2014.

*Projected Under GPASI

The reduction in solar installation costs over the past 24 months is expected to result in an 

increase of distributed solar projects in the service territory. Therefore, it is important for the 

Company to fully account for all the impacts of distributed generation on the electric distribution 

0.0

25.0

50.0

75.0

100.0

125.0

150.0

175.0

200.0

225.0

250.0

275.0

2006 2007 2008 2009 2010 2011 2012 2013* 2014*

0.005 0.02 0.05 1.5 4.4 55 61

166

271

Georgia Power Cumulative Contracted Solar 

Capacity 2006-2014

Megawatts
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system as well as to customers. Within the next few years, the Company intends to evaluate a 

pilot scale demonstration project that assesses the benefits and challenges associated with 

combining solar and Conservation Voltage Reduction (“CVR”). CVR is an active measure that 

reduces customers’ electricity demand by temporarily lowering the customer’s service voltage, 

while maintaining reliability. An increased amount of CVR demand reduction may be used to 

coincide with diminishing solar output that occurs during afternoon peak demand hours. The 

pilot project would analyze existing solar on the electric grid in combination with CVR to 

determine if there are any system benefits realized by this methodology. 

10.3.1 Large Scale Solar

On June 7, 2011, the Commission requested that Georgia Power and Commission Staff develop 

options for expanding large-scale solar projects. In response to the Commission’s request, the 

Company developed the 2015 LSS proposal. The Commission approved the Company’s LSS 

proposal on July 22, 2011 in Docket No. 34229 and ordered the Company to file the LSS 

program’s procedural details within 30 days. 

Under the LSS proposal, the Company purchased a total of 50 MW of solar capacity. This 

purchase was in addition to the Company’s current solar procurement activities and will add to 

the generation procured through the 2015 RFP. The Company entered into PPAs for terms of 20 

years for individual solar projects in Georgia that were greater than 1 MW, but less than or equal 

to 30 MW in size. 

These purchases were for a fixed energy amount at a preset solar price per MW hour (“MWh”) 

throughout the term of the PPA. The pricing was developed utilizing projected long-term 

avoided energy costs, plus a credit for the capacity that solar provides. The capacity component 

of the solar price was benchmarked to current market pricing obtained in the 2015 RFP. Under 

this avoided cost/market pricing methodology, customers were assured that the capacity resource 

procured was consistent with current economics while also gaining the benefit of additional fuel 

diversity. Participants kept the rights to the RECs produced by their projects. 
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Commission Staff conducted a first-come, first-served Notice of Intent process in September 

2011 and notified the Company of the winning participants. The Company subsequently 

negotiated, executed and received approval for all 50 MW of contracts. These projects have a 

required commercial operation date in 2015 but are projected to become operational as QFs 

sometime in 2013 and 2014. 

10.3.2 Georgia Power Advanced Solar Initiative 

On September 26, 2012, Georgia Power filed the GPASI in Docket No. 36325. This initiative 

complements other ongoing efforts to pursue cost-effective renewable resources and was 

designed to maximize opportunities for solar development by encouraging wider participation. 

The approach was simple: provide opportunities to develop solar resources (from small roof top 

to utility-scale), including mechanisms by which multiple entities can participate in that 

development. To that end, the GPASI program is expected to stimulate solar development in a 

cost-effective, responsible way that will bring additional solar generation to the Company’s 

customers. 

The resources procured under the GPASI will be in addition to the solar resources the Company 

currently procures through the Commission-approved Green Energy contract, SP and RNR 

tariffs, the LSS program, and other QF purchases. 

Through the GPASI, the Company will purchase energy from solar generation in two distinct 

ways: through (1) requests for proposals (the “GPASI RFPs”) from solar developers to fulfill an 

annual portfolio capacity target; and (2) smaller, distributed scale solar purchase offerings. 

Under the GPASI RFPs, Georgia Power expects to purchase up to 60 MW of utility scale solar 

generation per year, for two years, for a total procurement of 120 MW. Specifically, beginning 

in 2013, the Company will issue an RFP for 60 MW of additional solar, with an expected 

commercial operation date (“COD”) of January 1, 2015. In 2014, the Company will issue 

another RFP for 60 MW of new solar, with an expected COD of January 1, 2016. The Company 

will enter into PPAs for a term of 20 years for individual solar projects in Georgia that are 

greater than 1 MW and less than or equal to 20 MW in size. Each RFP will require bidders to 
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bid a “not-to-exceed” price of 12 cents per kWh, the calculation of which includes a capacity 

benefit that is benchmarked to market pricing obtained in the 2015 RFP in Docket No. 34218. 

The second component of the GPASI involves smaller solar facilities, up to 100kW in size, and 

mid-sized facilities, greater than 100 kW up to 1 MW in size. These two distributed scale solar 

purchase offerings are referred to as the “Small-Scale” and “Medium-Scale” options. Under the 

Small-Scale and Medium-Scale options, Georgia Power will purchase 90 MW of solar 

generation from customers and developers that are located in the Company’s service territory 

over a period of two years beginning in 2013, with any unused capacity rolled over to subsequent 

years. The Company will enter into contracts to purchase 100 percent of the energy from the 

solar capacity from both its retail customers and private developers at 13 cents per kWh. The 

Small/Medium Scale programs will procure a total of 45 MW of energy from the new solar 

capacity on a first-come, first-served basis each year, for two years, until the 90 MW limit is met. 

The GPASI was approved on November 29, 2012 and makes Georgia Power one of the national 

leaders among utilities operating in states in which there is no mandate for solar procurement. 

10.3.3 Distributed Solar Demonstration Projects

There are three solar demonstrations underway at Southern Company facilities. The first is 

located on the roof of the Georgia Power headquarters building in Atlanta, Georgia. The 

objective of this pilot-scale demonstration is to compare the performance and reliability of 

different commercially available PV technologies. Five technologies were installed by the end 

of the summer of 2009. The remaining two systems were installed in 2010. The Company has 

begun an evaluation to determine which technologies are best suited for the unique climate 

conditions of the southeastern United States. Preliminary results from the ongoing evaluation 

were published in an internal report by the Electric Power Research Institute (“EPRI”) in January 

2013 with a final report expected to be expected March 31, 2013. The demonstration project has 

already served as an educational platform for customers who are in the process of evaluating 

solar projects. The Company has hosted over 150 tours of the demonstration and also 

established a solar dashboard with internet access where stakeholders can see near real-time (15 

minute intervals) and historical production data for each of the technologies, along with 

associated weather data from the project’s weather station. 
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The Company seeks to revise the solar demonstration project at the Georgia Power headquarters 

building into a second phase once the final results of the initial solar demonstration are complete. 

The Company wishes to expand the demonstration project as a test bed for commercially viable 

solar technologies. The evolution of solar technologies requires that the Company continue to 

evaluate and test evolving commercial technologies to understand their performance in the 

unique climate of the Southeast. Upon completion of the initial phase, as outlined above, the 

Company intends to update the existing solar systems on the roof to reflect the most recent and 

emerging solar technologies. These technologies may include solar technologies developed 

locally and regionally. The research goals of the demonstration project would remain the same 

through evaluation of environmental impacts such as sunlight hours, temperature and humidity. 

The project will also seek to maximize output from the solar projects through a variety of system 

orientation and optimization factors. 

In addition, the Company seeks to implement a battery storage demonstration project as a 

compliment to the existing Georgia Power headquarters building solar demonstration. A battery 

storage system could be installed on one or more of the 4kW solar modules to help evaluate the 

benefits and costs of battery storage. This battery storage system would allow the output of a 

solar project to be shifted several hours to better align it with the summer peak of the utility. The 

Company expects the cost of modifying the Georgia Power headquarters building solar 

demonstrations to add both the battery storage evaluation and the newest commercially viable 

technologies would not exceed $200,000. Understanding this technology, including cost, 

operation, and maintenance will provide the Company valuable market knowledge and 

experience to assist customers with future inquiries. Much like the reporting for the first phase 

of the Georgia Power headquarters building solar demonstration project, the Company would 

work with a third party to document the results of the second phase of the demonstration project. 

As battery technology costs continue to decline, this project will provide the company with key 

technology performance information to identify the appropriate role of solar generation with 

storage in the company’s portfolio.

A second solar demonstration project, conducted by Southern Company Research & 

Environmental Affairs, is located on the rooftop of the Alabama Power headquarters building in 

Birmingham, Alabama. The objective of this pilot-scale demonstration is to gain system-wide 
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experience with micro-inverters being used on different commercially available solar 

technologies and to compare different module technologies, similar to the Georgia Power 

demonstration project. In addition to comparing energy production from various solar PV 

technologies, the Company will gain valuable information on the impacts of weather patterns on 

solar PV generation. The equipment was installed in 2010. This project is also being conducted 

in conjunction with EPRI and the results from the ongoing evaluation will be published in an 

internal report by March 31, 2013.

The third System solar demonstration project, also conducted by Southern Company Research & 

Environmental Affairs, is located at an Alabama Power facility in Mobile, Alabama. This site 

has seven ground-mounted systems, each with a capacity of approximately 2 kW, and has been 

in operation since October 2011. This project continues the work of the previous two projects 

but will focus on the specific effect of coastal weather on solar output.

In addition to the original evaluation and demonstration goals of these three projects, data from 

these installations are being used to evaluate both weather and PV generation modeling and 

simulation tools. Most of the widely adopted models used to generate solar resource data (such 

as those used to make the National Renewable Energy Lab’s solar resource maps) were designed 

relying heavily on modeled data. Combined, these demonstration projects are helping Georgia 

Power in the evaluation and refinement of these types of models, while also aiding in the 

development of more accurate generation profiles for system planning and other activities.

10.3.4 1 MW Solar Self-Build Demonstration

In the 2010 IRP, the Commission approved the Company’s request to develop a portfolio of solar 

demonstration projects totaling up to 1 MW to evaluate solar project siting, procurement, 

construction, and maintenance. The Company has evaluated several potential solar projects, 

including high profile sites at customer locations as well as installations at or on Companyowned facilities. The Company will continue to seek optimal locations to install this portfolio of 

projects totaling 1 MW and gain valuable experience in installing, owning and operating solar 

PV projects. 
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10.3.5 EPRI Distributed Photovoltaic (DPV) Project

Fifty solar PV units were installed on power poles located along selected Georgia Power 

distribution feeders in 2010. Another group of approximately 50 PV units was installed on 

selected distribution feeders in the Alabama Power service territory in 2011. The one-second 

data collected will be used to determine the impact of adding PV to the distribution system, to 

better understand the variability of PV performance, and to characterize other grid interface 

issues associated with this variable generation source. Among other benefits, these results could 

lead to a more effective and efficient interconnection process. Results from the ongoing 

evaluation of these PV units will be published in a report by EPRI in the first quarter of 2013.

10.3.6 Solar PV Tracking and Orientation Study

Due to the increasing prevalence of tracking technologies for solar PV applications and the 

potential for different orientations of fixed systems to have different impacts on capacity value 

(e.g., a west-facing system would have a peak output at a time that may better coincide with 

Georgia Power’s summer load peak), Georgia Power and Southern Company are considering a 

research project and demonstration involving different tracking technologies and system 

orientations. 

This project could test and demonstrate 250kW installations of each of the following 

technologies:

 Fixed-tilt, south facing PV panels (most standard technology, would serve as a control)

 Fixed-tilt, southwest facing PV (improved capacity value, decreased annual energy)

 Single-axis tracking (advanced technology, but becoming more common)

 Dual-axis tracking (most advanced technology) 

This 1 MW solar PV tracking and orientation project would evaluate the performance and 

operating characteristics of each configuration, using the same panel and inverter technology for 

each. The Company estimates that the cost of this demonstration will not exceed $5,000 per kW 

installed. Results would provide valuable operation data, as well as enable Georgia to gain 
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experience with these more advanced technologies. A real-time dashboard, similar to the current 

rooftop PV projects, may be provided for additional education purposes.

10.3.7 Concentrating Solar Thermal Applications Research

Southern Company participated in two supplemental solar projects with EPRI from 2008 to 

2010. These studies involved assessing the economics and feasibility of adding steam generated 

by a solar thermal field to a conventional fossil fuel-powered steam cycle, either to offset some 

of the fossil fuel required to generate electric power or boost plant power output. These were 

computer simulation projects, and the parameters entered came from actual coal and natural gas 

plants. The final reports are available to participants in supplemental projects. These studies 

found that this application is not currently feasible, due to the economics of the technology and 

the lack of the specific type of solar resource required for concentrating solar technologies in the 

Southeast.

Southern Company began participating in a supplemental project with EPRI in 2012 that will 

evaluate the potential for a lower temperature application of concentrating solar thermal 

technology. This study will be based on the thermal requirements of the carbon capture process 

in the 25MW carbon capture demonstration at Alabama Power’s Plant Barry near Mobile, 

Alabama. This application has potential to be better suited for integration of concentrating solar 

technology to offset the parasitic load on the plant induced by the chemical processes involved in 

carbon capture from flue gas.

10.3.8 Solar Water Heating Demonstration Projects

Eighty-gallon propylene glycol solar water heating systems were installed at four residences in 

Pensacola, Florida; Saraland, Alabama; Bainbridge, Georgia; and Long Beach, Mississippi. The 

objective of this project is to generate performance, reliability, and cost information sufficient to 

quantify the economics and technical viability of solar water heating applications across 

Southern Company’s service territory. The last of the four systems was installed during the 

summer of 2009, and data review has begun for all four sites. An internal project update report 

was issued during the first quarter of 2012. Data collected to date suggest that the solar thermal 

collectors can provide 70% or more of the annual energy needs for water heating, but system 
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reliability and cost could still be issues. Completion of data collection is anticipated during the 

second quarter of 2013, with a final report expected to be completed by the end of 2013.

10.3.9 Additional Solar Related Resources Available to Customers

The Company has also taken steps to provide more information and education for customers 

interested in learning more about solar generation options. For instance, the Company selected 

and trained 18 employees to serve as Solar Energy Consultants. These Solar Energy Consultants 

are located throughout each of the Company’s 11 regions across the state and are sources of 

information for customers who are interested in solar. In addition, information available on 

GeorgiaPower.com also aids customers in the evaluation of available solar generation options. 

The Company has received positive feedback regarding its Solar Energy Consultants and the 

additional solar-related information available at GeorgiaPower.com. These efforts support 

Georgia Power’s goal to provide expertise to its customers as they make energy decisions.

10.4 90 MW RENEWABLE SELF-BUILD PROJECT 

As part of the 2007 IRP, the Commission approved the Company’s request to develop up to three 

30 MW renewable energy projects that are at or below the Company’s avoided cost.

The Company continues to seek cost-effective renewable projects and has either evaluated, or is 

currently evaluating, landfill methane gas, digester methane gas, wood biomass, and solar PV 

projects with developers and customers. To date. evaluations have been made on over 30 

potential biomass, landfill methane gas, or digester methane gas projects and over 50 potential 

PV solar projects. However, no commitments have been made for specific self-build projects.

Contributing factors that have affected the development of renewable projects are:

1. Decreases in current projected avoided costs relative to prior projections, largely due to 

lower natural gas price forecasts, have made financial hurdles more difficult to clear.

2. Uncertainties created by pending EPA regulations and lower natural gas prices may 

adversely affect the economic viability of the biomass repowering projects.
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10.5 BIOMASS OVERVIEW

The Company continues to evaluate a variety of biomass generation options. Decisions on 

individual projects will depend on costs, regulatory/legislative requirements, biomass fuel 

availability and other site-specific factors.

Southern Company is conducting research at multiple locations on co-firing coal with wood 

chips, wood pellets, sawdust, urban wood waste, peanut hulls, switchgrass, and other biomass to 

determine the costs and impacts of the process. Additionally, Southern Power began commercial 

operation of a 100 MW biomass plant in Sacul, Texas on June 23, 2012. The plant will serve the 

city of Austin for 20 years and is one of the largest 100 percent biomass plants in the nation. 

10.5.1 Biomass Cofiring

The scope of Southern Company’s biomass testing program has included investigation of cofiring various types of biomass at existing pulverized coal power plants. Several studies have 

been conducted by Southern Company and Georgia Power regarding the feasibility and costeffectiveness of different co-firing technologies.

Southern Company has been working to develop a better understanding of the technical, 

environmental, and cost issues associated with co-firing up to 10 percent biomass by energy 

through direct injection in coal units. The studies defined the required additional equipment, 

equipment modifications, performance, environmental emissions, and costs associated with 

adding the biomass direct injection system to coal units. KEMA and Doosan were the 

Company’s contractors for these studies. The contractors also assessed the impacts of co-firing 

up to 10 percent biomass by energy on downstream emission control equipment. These studies 

were performed at units in Alabama and Georgia.

In general, there are two forms of co-firing. Co-milling involves treating the biomass as if it 

were coal, mixing the material with the coal and passing it through the coal handling system and 

coal burners. The other technology is direct injection, in which the biomass is processed to a 

fine sawdust-like material and blown directly into the furnace through its own dedicated burners 

or with the coal through existing burners. Co-milling requires less capital but is limited to only 

low percentages of biomass. Its success depends on the individual power plant design, the form 
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of biomass as fuel, and the percentage co-fired. The maximum percentage of co-milling energy 

will typically be about one to five percent as measured by energy input. In testing at Southern 

Company plants, sawdust and sander dust worked fairly well, as did finely chipped tree trimming 

waste. Less success was achieved with large wood chips due to their fibrous nature. Smaller 

wood chips, 1/2 inch or less in fiber length, worked better than the larger chips, but not quite as 

well as sawdust. 

Direct injection is generally capable of co-firing higher percentages of biomass. However, 

capital equipment is required, and the biomass (wood or grass) must be reduced to a small size, 

which can further add to costs. Encouraging results have been obtained in Southern Company 

power plant tests conducted on direct injection of switchgrass.

In addition to the biomass handling, feeding, and capital cost issues mentioned above, there are 

other key technical hurdles that must be overcome before biomass could be co-fired on a 

significant scale. Biomass materials have concentrations of certain minerals that are potentially 

adverse to the operation of the pollution control equipment located at many of the Company’s 

power plants. Southern Company is currently pursuing R&D to better define the effects of these 

minerals. Furthermore, many plants sell, rather than store, their fly ash for use in the concrete 

industry. However, the American Society for Testing and Materials (“ASTM”) International 

specifications for fly ash in cement does not recognize anything but fly ash from coal. As a 

result, there are concerns about the ability to sell fly ash that contains wood ash. Southern 

Company continues to partner with Georgia Tech to study the differences in coal only ash and 

biomass co-fired ash as discussed more fully below.

The current financial projections show that co-firing biomass can be economical with 

conventional coal-based power generation. Because a given volume of biomass contains much 

less energy than the same volume of coal, the transportation costs for biomass versus coal are 

much greater. This cost relationship adversely affects the economics of biomass power 

generation. The Company currently estimates that Georgia Power could realistically co-fire 

biomass to produce energy in the range of 30 to 80 MW at selected units.

Southern Company will continue to conduct a significant R&D program in biomass co-firing 

with the goal of solving the key technical issues and improving the economics. Southern 
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Company is actively engaged in addressing the technical issues and economic barriers that will 

permit increased use of this native resource for future power generation.

Southern Company has completed a series of small (1/2 inch and less) wood chip co-milling 

tests. The tests were conducted at units across the Southern Company fleet. The project 

explored the feasibility of using woody biomass as an energy source by blending it with coal and 

sending the fuel mix through the existing fuel handling system. The overall percentages of 

woody biomass that could be co-milled ranged from zero to three percent by energy. This 

number is lower than initially expected and is greatly influenced by excess pulverizer capacity, 

pulverizer type and fuel moisture. A test with wood pellets was also recently performed at an 

Alabama Power coal plant. During the test, a seven percent blend of wood by energy was 

achieved. Additional co-milling studies will be performed with torrefied wood as the fuel type at 

a Gulf Power coal unit in the near future. Torrefied wood is wood that has undergone extensive 

drying and heating and has the potential to be blended at very high percentages with coal, but the 

market is still in the pre-commercial stage, and it is very expensive when compared to coal or 

green wood pellets.

The Company, in conjunction with Southern Company, has evaluated several aspects of biomass 

co-firing at units across the fleet to determine feasibility and potential long term benefits. In 

addition, the prospect of compete conversion to biomass from coal is being evaluated at Plant 

Mitchell near Albany, GA.

10.5.2 Plant Mitchell Unit 3 Biomass Conversion

On March 26, 2009, the Commission certified the conversion of Plant Mitchell Unit 3 from a 155 

MW coal-fired electric generating station to a 96 MW biomass fuel-fired electric generating 

station (the “Mitchell Project”). 

At the time the certificate was issued, the Mitchell Project was expected to begin serving 

customers in the summer of 2012. However, subsequent to the Commission’s decision, the EPA 

delayed the release of the IB MACT regulation several times. The IB MACT regulation limits 

emissions from industrial boilers and applies to biomass-fired electric generating boilers. As a 
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result of the anticipated impact of EPA rulemakings on the Mitchell Project, the Company 

requested, and the Commission approved, a delay in construction of the Mitchell Project. 

On October 26, 2011, at the Company’s request, the Commission approved an additional two to 

four year delay due to uncertainties relating to pending EPA regulations. 

On December 2, 2011, the EPA issued a proposed IB MACT rule as part of its reconsideration of 

the rule that was finalized on March 21, 2011. As with prior versions of the rule, the newly 

proposed reconsideration contains stringent emission limits for several hazardous air pollutants. 

In a May 9, 2012 order, the Commission approved the Company’s plan to study the feasibility of 

using Direct Injection (“DI”) technology for the Mitchell Project. The Commission also ordered 

the Company to provide the Commission Staff the results of the DI study no later than the 

Company’s 2013 IRP filing. The Company shared the results of the study with the staff in 

January 2013. The study defines the required equipment modification, performance, 

environmental emissions, and cost associated with using DI for the Mitchell Project. 

On December 14, 2012 the EPA released a new National Ambient Air Quality Standard 

(“NAAQS”) for PM2.5. The Company is evaluating the new standard for any potential impacts 

on the Mitchell Project. The EPA originally planned to issue the new IB MACT rule in the 

spring of 2012. On December 21, 2012, the EPA issued the final reconsideration of the IB 

MACT rule. The Company is currently evaluating the rule and its impact on the Mitchell 

Project.

10.6 WIND ENERGY

Georgia Power and Southern Company are studying the feasibility of locating wind turbines on 

and offshore in the Georgia and Gulf of Mexico coastal regions. Past research results suggest 

that further evaluation is needed to determine exact resource potential for offshore wind. The 

Company proposes to continue evaluation of offshore wind in addition to exploring resource 

availability along coastal corridors and Appalachian ridge tops. Despite the uncertainty 

surrounding the future of production tax incentives, the Company is committed to continued 

evaluation of wind as a potential energy source both within and outside the service territory.
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10.6.1 Proposed Small Wind Demonstration Pilot Project

Georgia Power and Southern Company are evaluating a potential project to compare and 

evaluate several different small to medium (20-100kW) wind turbine technologies. Between 

four and six small wind turbines, of both horizontal and vertical axis designs, would be installed 

in the Georgia Power service territory. Participation from Georgia universities would be sought, 

with the potential for the project to be managed by a university research program. The intent of 

the demonstration would be to understand the feasibility of small scale wind generation as well 

as evaluating wind resources in various geographic areas of the state. These efforts are in 

addition to the Company’s continuing evaluation of utility scale off-shore wind installations. 

The Company expects the cost of the Small Wind Demonstration Pilot Project not to exceed 

$9,000 per kW installed. 

10.6.2 Georgia Coast Offshore Wind Feasibility Study

Southern Company and Georgia Tech’s Strategic Energy Institute collaborated on a study of the 

feasibility of locating wind turbines off the coast of Savannah, Georgia. The goal of the project 

was to determine if offshore wind power is an efficient and cost-effective renewable energy 

option for power generation. Design and conceptual engineering for the project was completed 

using technical expertise from both Georgia Tech and Southern Company. The study evaluated 

various technology options for wind turbines, platforms/foundations, submarine cabling, and grid 

interconnection. Detailed analyses of a site location and environmental regulations and 

jurisdictions, including permitting requirements, were also performed. A final report, titled 

Southern Winds, was completed in early 2007.

One of the findings of Southern Winds was that wind resource data were needed from the actual 

sites of the potential wind farm. Since 2007, work has continued to obtain offshore leases from 

the Department of Interior’s Bureau of Ocean Energy Management (“BOEM”) under its interim 

policy. An application was submitted to BOEM on April 7, 2011. An interim lease, if granted, 

would be for five years and only allow for the placement of a data collection system such as a 

fixed offshore meteorological tower for wind data collection. An addendum to the application 

has been submitted that would allow for a floating buoy with Light Detection and Ranging 
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(“LIDAR”) wind measurement technology as a possible lower cost alternative to a fixed 

meteorological tower. 

Following a BOEM Additional Information Request regarding the LIDAR alternative, a response 

was submitted in November 2012. Initial National Environmental Policy Act lease application 

process steps began as BOEM issued a December 2012 Federal Register Notice of Intent to 

prepare an Environmental Assessment, requesting public comment on the lease application. 

Coincidentally, following a previous Request for Information from the Department of Energy 

regarding any offshore energy resource evaluation efforts, a response was submitted in 

September 2012 updating them on the Company's efforts.

10.6.3 Gulf Coast Wind Measurement Project

A meteorological tower was installed at Navarre Beach, Florida, to examine the wind speeds 

along the Gulf Coast and their potential to match the utility load profile. The site on which the 

tower was installed is a strip of beach between the Gulf of Mexico and the Intracoastal 

Waterway. After the tower was installed in September 2009, data was collected at three different 

heights (40, 50, and 60 meters). The data have shown that the site is only a marginally 

acceptable resource for wind power generation, having an NREL Class 2 wind power density, 

while Class 4 is generally considered necessary for economically viable generation.

This meteorological tower was relocated in the second quarter of 2012 to the Navy Construction 

Battalion Center in Gulfport, Mississippi. Measurement readings began on June 1, 2012, and 

data is being shared with the Navy and the University of Southern Alabama meteorology 

department. The meteorological tower will remain in Gulfport for at least two years.

10.6.4 Off-System Wind Projects

On December 7, 2012, Alabama Power started receiving energy from the Oklahoma-based 

Chisholm View Wind Project as part of a 2011 PPA. This agreement is a 20-year contract 

through TradeWind Energy. Under this agreement, Alabama Power has the flexibility to use 

generated wind energy to serve customers and retire the associated RECs or sell the energy and 

RECs to others, either separately or bundled together. The Chisholm View Wind Project will 

produce up to 202 MW and is located in Grant and Garfield counties, Oklahoma. 
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Georgia Power is also evaluating the procurement of wind energy generated from wind farms 

across the Midwest and moving that power through existing transmission to the Southern 

Company service territory. Market conditions and transmission availability may allow for the 

procurement of wind resources that could be below current avoided cost projections. In addition 

to seeking opportunities to integrate various renewable energy resources to diversify the 

Company’s energy portfolio, the opportunity exists to put downward pressure on rates through 

purchasing cost effective wind energy generated in the Midwest.

10.7 INCREMENTAL HYDRO OVERVIEW

Georgia Power and Southern Company continue to identify and evaluate opportunities for 

incremental hydro resources. Incremental hydro refers to the incremental energy, ancillary 

benefits associated with transmission and, in some cases, incremental capacity obtained by 

upgrading existing hydro facilities. Upgrades to existing facilities are usually site specific and 

could range from replacing worn equipment (such as turbine runners) to replacing the entire 

powerhouse or installing a new powerhouse in an underutilized impoundment. Engineering 

studies have been completed to assess the feasibility and cost of upgrading certain Georgia 

Power hydro resources to better understand the improvement of unit efficiency and licensing 

constraints. Future economic studies will be completed subsequently to determine the timing 

and/or conditions appropriate for implementing any of the upgrades. If appropriate, the 

Company anticipates it would likely bring such projects before the Commission for approval 

prior to starting construction. 
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11 – HYDRO ELECTRIC 

OPERATION AND 

RE-LICENSING
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SECTION 11 - HYDRO ELECTRIC OPERATION AND RE-LICENSING

11.1 FOREWORD

Georgia Power operates 18 Hydro Electric Facilities and has an ownership interest in a 19th for a 

total of 71 generating units in Georgia. All but one of these facilities (Estatoah) is licensed under 

the Federal Power Act. These facilities provide 1,088 MW of capacity and have provided 

approximately 1,816,716 MWh of energy to the customers of Georgia over the 20-year period 

from 1993 to 2012. The following information details the re-licensing dates, schedules, 

requirements and estimated risk of environmental challenges to continued operation of these 

facilities.

11.2 GEORGIA POWER HYDRO PLANT RE-LICENSING SCHEDULE

The following description applies to re-licensing proceedings that will be ongoing over the next 

twenty years. 

Bartletts Ferry

License Expires 12/14/2014

The Notice of Intent to File Re-License Application was submitted in May 2009. Consultation 

with stakeholders continued through December 2012, when Georgia Power filed its license 

application with the Federal Energy Regulatory Commission (“FERC”). The FERC is expected 

to issue a new license by December 2014 that will likely include environmental enhancements. 

The scope of these potential enhancements is likely to include enhancements for dissolved 

oxygen, reservoir fluctuation limits, and improvements to recreation facilities.
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Georgia Power has spent and is expected to spend the following for re-licensing Bartletts Ferry:

2008: $207,000

2009: $525,000

2010: $866,000

2011: $871,000

2012: $1,000,000

2013: $400,000

2014: $400,000

2015: $260,000 (budgeted post-license enhancements)

2016: $1,000,000 (budgeted post-license enhancements)

========

Total: $5,529,000

Wallace Dam

License Expires 6/01/2020

The Re-license process is scheduled to start in 2013; a Notice of Intent to File Re-license 

Application must be filed prior to June 1, 2015.

Expected Costs of Re-licensing Wallace Dam:

2013: $200,000

2014: $300,000

2015: $1,000,000

2016: $1,000,000

2017: $1,000,000

The remaining years have not been budgeted but are expected to be of similar magnitude.
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Langdale, Riverview, and Lloyd Shoals Projects

License Expires 1/01/2024

The Re-license process is scheduled to start in 2017; a Notice of Intent to File Re-license 

Application must be filed prior to January 1, 2019.

Rocky Mountain Pumped Storage Project (Co-owned and Jointly Licensed with 

Oglethorpe Power)

License Expires 1/01/2027

The Re-license process is scheduled to start in 2020; a Notice of Intent to File Re-license 

Application must be filed prior to January 1, 2022.

Sinclair Project

License Expires 5/01/2036

The Re-license process is scheduled to start in 2030; a Notice of Intent to File Re-license 

Application must be filed prior to May 1, 2031.

North Georgia Project (includes Burton, Nacoochee, Terrora, Tallulah, Tugalo, Yonah)

License Expires 9/01/2036

The Re-license process is scheduled to start in 2030; a Notice of Intent to File Re-license 

Application must be filed prior to September 1, 2031.

11.3 REQUIREMENTS AND RISK TO RE-LICENSING REQUIREMENTS

Georgia Power is not currently considering any changes to its operations for the re-licensing 

proceedings at Bartletts Ferry and Wallace Dam. However, during re-licensing, requirements 

may be imposed by the FERC (resulting from input from federal and state agencies, nongovernmental organizations, and other stakeholders). Outside of the FERC re-licensing 

proceeding, requirements may be imposed during a license term by the U.S. Fish and Wildlife 

Service, U.S. Forest Service, or National Park Service through prescriptive authority under the 

Federal Power Act or by state agencies under Section 401 permits of the Clean Water Act.
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Any of these potential requirements can lead to the following impacts or risk to the Company’s 

continued operation of hydro projects. 

Risk

Loss of generation and/or capacity from:

 Increased minimum flows;

 Seasonal limits on generation; 

 Increased water withdrawals;

 Limits on reservoir fluctuations; or

 Dam removal (less likely for larger hydro projects).

Reduction in peaking capability, reliability, ancillary services (e.g., voltage control), and 

operational flexibility from:

 Imposed ramping rates; or

 Modifications to current operational regimes.

Increased capital investments arising from:

 Installation of fish passage facilities;

 Installation of environmental enhancement facilities (e.g., dissolved oxygen);

 Installation of additional recreation facilities;

 Shoreline changes;

 Habitat enhancement;

1) Monitoring and surveillance of environmental parameters; or 

2) Replacement of capacity/energy.
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12 – WHOLESALE 

GENERATION
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SECTION 12 - WHOLESALE GENERATION

12.1 OVERVIEW

In recent years, the Company has offered certain wholesale capacity blocks to the retail 

jurisdiction pursuant to the Company’s agreement with Commission Staff in Docket No. 26550. 

The recent decisions on returning wholesale capacity to retail are described below. The 

Company’s requirements service contract with the city of Hampton ended on December 31, 

2012. The Company is considering additional potential long-term requirements service 

agreements with certain wholesale customers as described below. The Company has also signed 

new long-term contracts to serve Flint EMC.

12.2 WHOLESALE CAPACITY TO RETAIL

On July 27, 2009, the Commission issued an order in Docket No. 26550 accepting into retail 

Blocks 5 and 6 offer of 178 MW of oil-fired peaking capacity. Portions of the Blocks 5 and 6 

capacity will become available to retail at different times as the existing wholesale contracts 

expire, with the total capacity in retail rate base on January 1, 2016. With the retirement of the 

Mitchell 4C unit in March 2012, the capacity is reduced to 169 MW and will remain in retail rate 

base until the end of the assets’ lives. The Commission certified Blocks 5 and 6 on March 5, 

2010. 

On September 15, 2009, the Commission issued an order accepting approximately 78 MW of 

Scherer Unit 3 coal-fired capacity. Approximately 54 MW will become available to retail on 

January 1, 2016, with the additional 24 MW on June 1, 2016. The approximately 78 MW 

Scherer Unit 3 resource will remain in retail rate base for 15 years (until 2031). The 

Commission certified the Scherer Unit 3 capacity on March 5, 2010.

On October 8, 2010, the Commission issued an order accepting Georgia Power’s offer of 250 

MW of Block 1 coal-fired capacity that will become available to retail on April 1, 2016 and 312 

MW of Blocks 2-4 coal-fired capacity that will become available to retail on January 1, 2015. 

With the retirement of Branch Units 1 and 2 effective December 31, 2013 and October 1, 2013, 

respectively, the capacity of Block 1 and Blocks 2-4 will be reduced to 229 MW and 266 MW, 

respectively, and will remain in retail rate base until the end of the assets’ lives. If the 
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Commission decertifies additional units included in the wholesale blocks described above, then 

the capacity of the blocks available to retail will be reduced. On March 26, 2012, the 

Commission issued an order certifying Block 1 and Blocks 2-4. 

12.3 WHOLESALE REQUIREMENTS CONTRACTS

As of January 1, 2013, the Company no longer provides requirements service to the city of

Hampton. As a result, Hampton’s load (approximately 9 MW) and generation need is not 

integrated into the Company’s resource planning process. Therefore, in the 2013 rate case, the 

Company will not allocate the cost to serve Hampton to the wholesale jurisdiction.

The Company is considering additional potential long-term requirements service agreements 

with other wholesale customers and may provide such requirements service under additional 

long term agreements (e.g., 20-30 years). 

The requirements agreements would involve joint integrated long-term planning of wholesale 

and retail loads and generation resources. The wholesale customers’ load and generation 

resources would be combined with Company load resources for planning as well as generation 

commitment and dispatch, thereby resulting in greater economies of scale. The Company would 

own (or purchase) new incremental generation required to serve its total load, including the 

wholesale requirements obligations. Any proposals would be subject to Commission approval of 

the IRP, which includes the subject requirements load. 

The benefits of additional long-term requirements agreements include joint planning of 

generation and transmission capacity as well as economies of scale resulting in capacity and 

energy savings. 

12.4 FLINT EMC CONTRACTS

The Company currently provides Flint EMC with 25 MW of Blocks 5 and 6 peaking capacity 

under an agreement that extends through December 31, 2014. The Company has also signed an 

agreement to provide 25 MW of Blocks 5 and 6 peaking capacity to Flint EMC from January 1, 

2015 through December 31, 2024.
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The Company currently provides Flint EMC with 56 MW of Scherer Unit 3 capacity under an 

agreement that extends through December 31, 2014 and another 24 MW of capacity under an 

agreement that extends through December 31, 2019. The Company has also signed an 

agreement to provide 56 MW of Scherer 3 capacity to Flint EMC from January 1, 2015 through 

December 31, 2029.
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13 – ACTION PLAN
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SECTION 13 - ACTION PLAN 

The Company’s action plan is as follows:

 Build, operate, and maintain the necessary generation, transmission, and distribution 

infrastructure to serve the growing needs of Georgia;

 Maintain long-term system planning reserve margin target of 15 percent;

 Continue to implement and develop all transmission and distribution projects necessary 

to ensure adequate reliability to the customers in the state of Georgia; 

 Meet all environmental requirements;

 Request decertification of Plant Branch Units 3 and 4, Plant Yates Units 1-5, and Plant 

McManus Units 1 and 2 effective by the MATS compliance date of April 16, 2015, 

decertification of Plant Kraft Units 1-4 one year past the MATS compliance date (by 

April 16, 2016), decertification of Plant Boulevard Units 2 and 3 effective as of the date 

of the final order in this proceeding, and approval of expedited decertification of Plant 

Bowen Unit 6 by April 16, 2013 as specified in the 2013 Decertification Application;

 Request approval of a switch to natural gas as the primary fuel for Plant Yates Units 6 

and 7 and Plant Gaston Units 1-4; 

 Request an amendment of the decertification date specified in the Commission’s final 

order in Docket No. 34218 for Plant Branch Unit 1 from December 31, 2013 to coincide 

with the decertification of Plant Branch Units 3 and 4 to enable its use as a startup boiler 

for Plant Branch Units 3 and 4;

 Request approval of the reclassification of the remaining net book values of Plant Branch 

Units 3 and 4 and Plant Boulevard Units 2 and 3 as of their respective retirement dates to 

regulatory asset accounts and the amortization of such regulatory asset accounts ratably 

over a period equal to the respective unit’s remaining useful life approved in Docket No. 

31958;

 In the event the Commission does not approve the expedited decertification of Plant 

Bowen Unit 6, request approval of the reclassification of the remaining net book value of 

Plant Bowen Unit 6 as of its respective retirement date to regulatory asset account and the 

amortization of such regulatory asset accounts ratably over a period equal to the 

respective unit’s remaining useful life approved in Docket No. 31958;
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 Request approval of the amortization of approximately $38 million of Plant Branch Units 

3 and 4 and approximately $14 million of Plant Yates Units 6 and 7 environmental CWIP 

(which has been reclassified as a regulatory asset in accordance with the Commission’s 

Order in Docket No. 31958) ratably over a three year period beginning January 2014;

 Request approval of the reclassification of any unusable M&S inventory balance 

remaining at the unit retirement dates to a regulatory asset as identified in accordance 

with the Commission’s Order in Docket No. 31958 for recovery over a period to be 

determined by the Commission in the Company’s next base rate case following the unit 

retirements;

 Request approval of the capital and O&M costs (but not yet the recovery) of measures 

taken to comply with existing government-imposed environmental mandates, as set out in 

the Selected Supporting Information section of Technical Appendix Volume 2;

 Request approval of the capital costs the Company will incur for a portfolio of certain 

renewable demonstration projects (but not yet the recovery of such costs), as set out in 

the Selected Supporting Information section of Technical Appendix Volume 2;

 Request approval of a certificate of public convenience and necessity for one new DSM 

program, a certificate amendment for three previously certified programs, decertification 

of one DSM program, and approval of updated program economics for previously 

certified energy efficiency DSM programs as further specified in the 2013 DSM 

Application in Docket No. 36499;

 Continuation of the Power Credit program and the additional DSM programs detailed in 

Section 5.2.2, 5.2.3, 5.2.4 and 5.2.5;

 Continue to provide customer information on cost-effective energy saving options that 

are available in the market and provide customer specific information as required;

 Utilize Qualified Facility contracts and continue to encourage additional resources in 

compliance with PURPA and the Commission’s Avoided Cost Order, Docket No. 4822;

 Continue to promote and expand the TOU-REO and TOU-PEV rates for residential 

customers;

 Continue to assess opportunities to integrate cost-effective renewable resources into the 

Company’s supply mix;

 Take actions to enable the option for additional generating capacity in the future; and
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 Implement GPASI.
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14 – ATTACHMENTS
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SECTION 14 - ATTACHMENTS

ATTACHMENT 14.1 – MAJOR MODELS USED IN IRP

Economic Model

Georgia Power’s econometric forecasting models (see below) use forecasts of various key 

economic and demographic variables for the state of Georgia. These forecasts are developed by 

Moody’s Analytics whose large-scale macroeconometric models produce economic and 

demographic forecasts for the U.S. and for the state of Georgia. Moody’s Analytics models are 

proprietary.

Residential End-Use Energy Planning System 

REEPS is an end-use model that is used to develop a long-term energy forecast of the residential 

sector. REEPS was developed under an EPRI contract in conjunction with Regional Economic 

Research, Inc.

Commercial End-Use Model 

COMMEND is an end-use model that is used to develop a long-term energy forecast of the 

commercial sector. COMMEND was developed under an EPRI contract in conjunction with 

Regional Economic Research, Inc.

Industrial End-Use Forecasting Model 

INFORM is an end-use model that is used to develop a long-term energy forecast of the 

industrial sector. INFORM was developed under an EPRI contract in conjunction with Regional 

Economic Research, Inc.

Econometric Forecasting Models 

Various econometric forecasting models are used to estimate the relationships between economic 

and demographic variables and energy use and demand. These models use ordinary least squares 

regression techniques.
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Hourly Electric Load Model (HELM)

HELM is a peak demand model that produces a forecast of peak demand using forecasted class 

energy, historical class load shapes and corresponding weather, and a description of typical 

(normal) weather.

SERVM

The Strategic Energy and Risk Valuation Model (SERVM) is a generation reliability model 

developed by the System in conjunction with an outside consulting firm to evaluate reliability.

SERVM is an hourly, chronological model using Monte Carlo techniques. Random numbers are 

used to model unplanned outages based on historical time to failure and time to repair data for 

the system units. The model executes beginning with hour 1 (Midnight - 1 A.M. on January 1), 

committing units, tracking available hydro energy, operating pumped storage units, and calling 

interruptible load as needed, recording the calls.

The annual processing is performed typically 100 times with the results averaged. This 

evaluation is performed for each weather-hydro year chosen for the study (typically the previous 

50 years) and for each of six economic load forecast errors.

Useful information provided by SERVM includes:

 Expected unserved energy – the amount of energy that cannot be served due to generating 

capacity shortages; 

 Reliability and Emergency Purchases - the amount of energy purchased from others at a 

cost in $/MWh that is higher than the energy cost of a combustion turbine;

 Loss of load hours – the number of hours in which some load is not served, with statistics 

concerning distribution throughout the year; and

 Interruptible load – the number of times that interruptible load is called, with statistics 

concerning distribution throughout the year.
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SERVM is a major tool providing input for numerous studies. It is used in: 1) developing the 

target reserve margin; 2) developing interruptible service riders; 3) developing loss of load hour 

tables in PRICEM; and 4) developing incremental capacity equivalent (“ICE”) factors. 

PROSYM

PROSYM is used to estimate marginal energy cost for use in various models and analyses. It is 

also used to project marginal sulfur dioxide (“SO2”) allowance costs. PROSYM is an hourly 

model that utilizes Monte Carlo techniques to randomly simulate the unit forced outages.

The useful information that can be gathered from PROSYM includes:

 Projections of marginal energy cost by hour for 20 years into the future;

 Projections of the SO2 marginal cost of serving an additional block of load; and

 The cost effects of changing the characteristics of individual units, such as changing heat 

rates, station service requirements, or similar factors.

PROSYM supplies important data to many studies. It is or has been used in: (1) determining the 

worth of improving existing units; (2) developing the marginal energy cost for use in PRICEM 

and elsewhere; and (3) developing the SO2 marginal cost for use in PRICEM.

REVREQ

REVREQ is a financial program used to convert capital expenditures into annual revenue 

requirements. It incorporates projections of the costs of capital, tax rates, and depreciation rates.

The useful information that can be gathered from REVREQ includes:

 Annual revenue requirements necessary to earn a return on and return of the investment;

 Net present value of revenue requirements; and

 Levelized fixed charge rates.

REVREQ provides a key calculation for numerous studies. It is or has been used in: (1) 

calculating revenue requirements streams for PRICEM; (2) calculating the economic carrying 
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cost rates and net present value of revenue requirements for many studies including, for example, 

for use in Strategist®/PROVIEWTM.

Strategist®/PROVIEWTM

PROVIEWTM is a generation planning optimization module of the Strategist® production cost 

model. It uses dynamic programming techniques to calculate the total capital and operating costs 

for hundreds of combinations of generating units. It calculates the minimum cost combination of 

units.

The useful information that can be gathered from Strategist®/PROVIEWTM includes:

 Least cost combination of generating unit additions by year;

 Additional cost of generation expansion plans that are not the least-cost plan; and

 Estimates of fuel use by fuel type.

PROVIEWTM is the basis of the benchmark plan. Sensitivity analyses performed through 

Strategist®/PROVIEWTM provide information for developing a combination of generating units 

that will provide a good combination of flexibility, risk reduction, and other considerations. 

Strategist® is used to integrate the supply-side options and the demand-side programs to produce 

the IRP. Strategist®/PROVIEWTM are also used to evaluate bids received in the competitive 

bidding process.

PRICEM

The Profitability Reliability Incremental Cost Evaluation Model (“PRICEM”) is a spreadsheetbased marginal cost model designed to estimate a change in revenue requirements and other 

effects attributable to changes in loads and/or revenues. PRICEM was developed by the System 

and takes data from other major models, combining them in a single spreadsheet to provide for 

quick, yet relatively detailed, evaluations of options. Data inputs are consistent with inputs to 

Strategist®/PROVIEWTM and as such are taken from: (1) revenue requirements streams from 

REVREQ, (2) marginal energy cost from PROSYM, (3) ICE factors from SERVM, and (4) 

Generation Technology Data Book assumptions.
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PRICEM models the year with 864 load points and uses the peaker method, a technique allowing 

the total of generating capacity cost and energy cost to be estimated with peaking capacity and 

marginal energy cost. The peaker method allows for quick screening of many alternatives. 

Useful information that can be gathered from PRICEM includes:

 RIM - A net present value calculation of the total benefits and total costs over the life of 

the program; and 

 Predictions of the amount of generating capacity needed to maintain System reliability 

after a change in interruptible or firm loads.

EnerSim

EnerSim is Southern Company’s proprietary hourly building energy simulation model. It has 

been certified and approved by the U.S. Department of Energy (“DOE”) and is listed on their 

website as “Qualified Software”. EnerSim predicts hourly energy consumption in buildings 

based on construction characteristics, insulation, occupancy, orientation, local weather, and 

equipment. RateSim, the rate analysis tool within EnerSim, uses the hourly energy data to 

estimate monthly energy bills. Finally, the hourly energy data, or loadshape, is used in PRICEM 

along with the energy bills from RateSim.

EnerSim is used to calculate the building energy load profiles of weather-sensitive energy 

efficiency measures, such as heating and cooling equipment upgrades, and insulation and 

weatherization improvements.

GenVal

GenVal is a model that is used to project the economic dispatch of a generating unit within the 

Southern Company fleet of resources. It utilizes hourly marginal costs from PROSYM, as well 

as the operating characteristics of the generating unit to be analyzed. The useful information that 

can be gathered from GenVal includes the system production cost impacts due to the inclusion of 

the generating unit within the Southern Company generation fleet.
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ATTACHMENT 14.2 – TECHNOLOGY SCREENING

Table 14.2.1 TECHNOLOGY SCREENING

Technology Description Status

1. Subcritical Pulverized 

Coal (Conventional 

Pulverized Coal)

This technology is mature with a large number 

of units on the system. New units would 

include the latest emission control systems to 

ensure compliance with all applicable 

environmental regulations and permit 

requirements.

RETAINED for 

further screening.

2. Supercritical Pulverized 

Coal 

This technology is mature with several units on 

the system. Environmental performance would 

be similar to subcritical pulverized coal.

RETAINED for 

further screening.

3. Ultrasupercritical 

Pulverized Coal (USC)

This technology involves the evolution of coalfueled generation to slightly higher steam 

pressures and temperatures than supercritical 

conditions to attain higher thermal efficiency. 

It also includes design for flexible operation, 

including the maintenance of higher 

efficiencies at partial loads. Many of these 

advanced features will gradually be 

incorporated into new base load coal-fueled 

capacity as they are made available through 

U.S. and international research efforts. The 

environmental performance would be similar to 

subcritical pulverized coal. Material 

capabilities limit the practical design of this 

unit, though currently there are operating 

designs that exceed supercritical limits (main 

steam conditions around 3600psia and 1100F).

RETAINED for 

further screening.

4. Advanced 

Ultrasupercritical 

Pulverized Coal (AUSC)

This technology represents the targeted design 

of current US and international USC research 

and embodies coal-fueled generation to steam 

conditions higher than that achieved by existing 

ultrasupercritical pulverized coal technology for 

even higher thermal efficiency (steam 

conditions approaching 5000psia and 1400F). 

The environmental performance would be 

similar to subcritical pulverized coal. This 

technology is nearing demonstration phases but 

requires more materials development to be 

completed.

Dropped from 

further screening 

due to current level 

of development.

5. Atmospheric Fluidized 

Bed Combustion (AFBC)

This technology includes both bubbling bed 

designs and circulating bed designs. AFBC 

technologies have the potential for sulfur 

removal without add-on flue gas scrubbers. 

Dropped from 

further screening 

due to economic 

reasons.
14-155

Technology Description Status

AFBC is currently better suited to industrial 

cogeneration and is probably the technology of 

choice for low grade, high ash coals and is 

typically limited to 300MW in size. When 

combined with future supercritical materials, 

AFBC economics may improve.

6. Pressurized Fluidized 

Bed Combustion (PFBC)

These plants could be produced as modular 

factory assembled units, but there are reliability 

concerns with particulate removal at high 

temperature and pressure, possible corrosion 

and erosion in the bed, and uncertainties with 

the cost of large pressure vessels. Vendors 

have recently stopped marketing and 

development efforts of PFBC.

Dropped due to 

lack of commercial 

development.

7. Topping PFBC In this concept, the coal feed is partially 

gasified to produce a low-Btu fuel gas, and the 

residual char is burned in a PFBC combustor. 

The flue gas is used as the oxidant to burn the 

fuel gas and raise the gas turbine inlet 

temperature to 2,750o F. Vendors have recently 

stopped marketing and development efforts of 

TPFBC.

Dropped due to 

lack of commercial 

development.

8. Oxygen-Blown IGCC This concept has potential for modularity, 

staged construction, and improved efficiency 

and environmental performance over pulverized 

coal-firing. Capital cost is an important 

concern of the technology and the use of 

advanced turbines is necessary for further 

efficiency improvement. Southern Company 

has constructed a power system test facility in 

conjunction with DOE to refine IGCC. Based 

on most current studies of CO2 capture for a 

coal-fueled power plant, IGCC has a cost 

advantage over pulverized coal because the 

CO2 in the gas stream is much more 

concentrated and at a higher pressure.

RETAINED for 

further screening.

9. Air-Blown Integrated 

Coal Gasification 

Combined Cycle

This technology is based on an advanced 

concept using an air blown transport gasifier 

and associated combustor. Air blown IGCC 

offers lower capital costs and higher efficiency 

compared to oxygen blown IGCC. Commercial 

deployment is underway at Plant Ratcliffe in 

Mississippi and in China. Further 

improvements to the technology are being 

evaluated at the NCCC facility operated at 

RETAINED for 

further screening.
14-156

Technology Description Status

Southern Company in conjunction with the 

DOE that have the potential for lower capital 

cost and higher efficiency.

10. Non-Integrated Coal 

Gasification Combined 

Cycle

This concept holds promise for modularity and 

staged construction. Capital cost is an 

important concern of the technology and the 

development of advanced turbines is necessary 

for further efficiency improvement.

Dropped from 

further screening 

because the 

integrated version 

would be more 

cost-effective and 

efficient.

11. Integrated Gasification 

Fuel Cell Combined Cycle

This is a future concept that depends on the 

development of advanced fuel cells that would 

be substituted for combustion turbines in the 

gasification combined cycle plant to provide 

high efficiency and extremely low 

environmental emissions. The 

commercialization of this concept is still 

uncertain given its dependence on the 

development of several advanced technology 

concepts.

Dropped from 

further screening 

due to its low level 

of development and 

high degree of 

uncertainty with 

cost projections.

12. 

Magnetohydrodynamics 

(MHD)

MHD appeal is high efficiency and inherent 

SO2, nitrogen oxide (“NOx”), and particulate 

control. The key developmental component is 

the MHD generator, in which a conducting 

exhaust gas from the combustion of coal along 

with seed material is passed through a magnetic 

field to produce DC electricity. The bottoming 

cycle is a conventional boiler and steam turbine. 

However, progress with MHD remains slow to 

stagnant and conceptual estimates indicate very 

high cost.

Dropped from 

further screening 

due to the level of 

development and 

cost uncertainties.

13. CT (Conventional/ 

Advanced)

Many conventional units exist on the system. 

The technology is mature, but advanced designs 

offer even higher turbine inlet temperatures for 

improved efficiencies. The increasing turbine 

temperatures will open new reliability 

questions. CTs can be applied as peaking 

capacity and in combined cycle plants using 

natural gas or oil. Advancements are being 

closely monitored. State-of-the-art combustion 

NOx control systems will be incorporated in the 

designs.

RETAINED for 

further screening.

14. CC 

(Conventional/Advanced)

Units are in operation on the system and the 

technology is mature. Future designs using 

more state-of-the-art CTs will offer better 

RETAINED for 

further screening.
14-157

Technology Description Status

economies (see CTs above). Vendors are now 

offering new CT designs with increased turbine 

inlet temperatures for improved CC 

efficiencies. Each of the major OEMs now 

offer packaged CC plants, based on advanced 

gas turbine technology, which offer greater 

thermal efficiencies and increased operational 

flexibility compared to conventional units. 

State-of-the-art NOx control systems will be 

incorporated for environmental compliance. A 

number of advanced CT-based cycles such as 

the CHAT, HAI, and Kalina cycles have the 

potential for higher thermal efficiencies, 

however they have not been commercially 

demonstrated.

15. Phosphoric Acid Fuel 

Cells

Phosphoric acid electrolyte systems using 

natural gas are the most mature fuel cell 

technology and as such have the most extensive 

track record for operational experience. Recent 

industry activity from UTC Power suggests 

renewed commitment to PAFC technology. 

This system has shown improvements as well 

as a reduction in cost. Attractive features 

include modular construction, low 

environmental impact, siting flexibility, and 

high efficiencies at small sizes.

RETAINED for 

further screening.

16. Advanced High 

Temperature Fuel Cells -

Molten Carbonate Fuel 

Cell (MCFC) and Solid 

Oxide Fuel Cell (SOFC)

Fuel cells using molten carbonate or solid oxide 

electrolyte may be more attractive than the 

phosphoric acid or PEM fuel cell. Since these 

fuel cells are operated at high temperatures 

(600-1000 ̊C), the incentives include higher 

efficiencies; more flexible and simplified fuel 

processing and use of inexpensive catalyst. 

Also, by-producing heat at these high 

temperatures, there are more applications than 

phosphoric acid systems, such as cogeneration 

and incorporation of a bottoming cycle. These 

fuel cells also have potential for use with coal 

gasification in integrated gasification fuel cell 

power plants. About 40 units are in the field 

with capacities ranging from 250kW to 1 MW. 

Cost, material selection under high temperature 

operation, and cell durability remain important 

issues. Fuel Cell Energy is the only 

commercializer in the US for MCFC 

RETAINED for 

further screening.
14-158

Technology Description Status

technology. SOFC is also moving up on the 

technology maturity curve, but they are at least 

a couple years behind the MCFC. However, 

their long term cost projection is lower than that 

of MCFC. Environmental characteristics are 

expected to be excellent for all fuel cell 

technologies.

17. Fuel Cell CC (FCCC) See Advanced High Temperature Fuel Cells. 

By-product heat from MCFC or SOFC can be 

used in bottoming cycles to produce additional 

power. Siemens demonstrated a pressurized 

220 KW SOFC/MT hybrid in Ca. and achieved 

52 percent efficiency even though the system 

was not optimized. FuelCell Energy is also 

testing an atmospheric MCFC/MT hybrid 

system. DOE Vision 21 power plant highlights 

such system at efficiency of 60-70 percent (80-

90 percent with thermal) with 0 air pollutants 

and CO2 (with sequestration) by 2015. The 

costs from such a system should be at par with 

market rate.

RETAINED for 

further screening.

18. Reciprocating Engines 

/ Microturbines

Diesel or gas fired generators and microturbines 

could potentially have economics competitive 

with combustion turbines at very low capacity 

factors and for dispersed applications. 

Microturbines are emerging in niche markets 

around the world, mostly in co-generation 

applications. The current trend is towards larger 

systems with heat recovery and/or chillers. 

There are environmental concerns due to 

relatively high emission rates for certain 

pollutants when burning diesel fuel.

Dropped from 

further screening 

since the 

applications for 

dispersed 

generation are very 

site-and customerspecific.

19. Pumped Storage 

Hydroelectric

Pumped hydroelectric energy storage is a large, 

mature, and commercial utility-scale 

technology used at many locations in the United 

States and around the world. Southern 

Company currently applies this technology on 

its system. This application has the highest 

capacity of the energy storage technologies 

assessed, since its size is limited only by the 

size of the available upper reservoir. Facilities 

of this type must deal with environmental issues 

related to land use and the availability of the 

water source.

RETAINED for 

further screening.

20. Underground Pumped Underground pumped storage hydro could avert Dropped from 
14-159

Technology Description Status

Storage Hydroelectric 

(UPH)

the environmental and licensing problems of 

conventional above ground facilities. The high 

excavation costs and long lead times of UPH 

significantly reduce its attractiveness. A 1000 

MW underground pumped storage generation 

facility is being developed in Wiscasset, Maine.

further screening 

due to high cost and

stage of technology 

development.

21. Compressed Air 

Energy Storage (CAES)

CAES plant hardware is commercially 

available. The first CAES (290 MW) plant was 

constructed in Germany in 1978. A 100 MW 

plant was constructed by Alabama Electric 

Cooperative and began commercial operation in 

June 1991 and is an integral part of AEC 

dispatch. There are several design 

configurations for new advanced CAES plants 

including combustion turbine based and 

adiabatic cycles using thermal energy recovery 

and storage. Although subsystems have been 

proven, the advanced cycles have yet to be 

demonstrated as an integrated system. CAES 

cycles can utilize either above ground (low 

MW) or below ground (high MW) energy 

storage options. The potential for large scale 

energy storage depends on suitable geology for 

constructing the air storage reservoir. The 

preferred geology for Southern Company would 

be salt dome sites in Mississippi and Alabama. 

CAES has the potential for better local 

environmental characteristics than pumped 

hydro. Brine disposal may be an environmental 

concern during reservoir construction. 

RETAINED for 

further screening.

22. Lead/Acid and 

Advanced Batteries (Load 

Leveling, UPS)

Lead/acid technology is mature, but life at 

elevated operating temperature with heavy duty 

cycles is of concern. Advanced batteries are 

being developed to achieve higher energy 

and/or power density, higher reliability, lower 

maintenance and longer life at a cost that can be 

competitive to conventional lead acid batteries. 

Potential applications include load 

management/peak shaving applications to defer 

the power plant construction for peaking 

capacity and backup power for T&D 

substations. Environmental impact on the local 

area is expected to be very low when the 

charging source is not considered.

RETAINED for 

further screening. 

(advanced battery)

23. Flywheel Energy Flywheels store mechanical energy, with the Dropped from 
14-160

Technology Description Status

Storage amount dependent on the inertia and rotational 

speed of the flywheel. Southern Company has 

demonstrated flywheel feasibility in short term 

ride-through for power quality (PQ) 

applications with very good success, but 

systems for high energy storage applications for 

peak shaving and/or load leveling are still 

undeveloped. Acceptable total system costs 

have been achieved with the PQ units and the 

ability to integrate the mechanical and power 

electronic components has been demonstrated. 

Monitoring of activity in the MW class systems 

continue and further cost reductions for 

composite materials, magnetic bearings, and 

power electronics will improve the chances for 

future electrical energy storage applications.

further screening 

due to the early 

status of 

development and 

better suitability for 

dispersed 

generation 

applications.

24. Nuclear Advanced 

Light Water Reactor –

Evolutionary

These plants are similar in design to Hatch, 

Farley and Vogtle but incorporate many 

evolutionary improvements in areas such as 

controls, systems, materials, construction 

techniques, and a streamlined regulatory 

approval process. Plants in this category 

include the Advanced Boiling Water Reactor 

(“ABWR”) by GE and Toshiba, Advanced 

Pressurized Water Reactor (“APWR”) by 

Mitsubishi and the European Pressurized Water 

Reactor (“EPR”) by Areva. ABWRs are in 

operation in Japan, and have been considered 

for several sites in the US. The APWR has 

been discussed for several US sites, but no 

license applications have been submitted to 

date. The EPR design is being built in Europe, 

and a modified version has been submitted for 

certification in the US. The evolutionary 

designs have the same environmental 

characteristics as the current fleet of light water 

reactors.

RETAINED for 

further screening.

25. Nuclear Advanced 

Light Water Reactor –

Passive

Southern Company has made a commitment to 

this technology as evidenced by the ongoing 

construction of two AP1000 (1000 MW) 

nuclear units at the Vogtle site for commercial 

operation in 2017 and 2018. In addition to the 

Westinghouse AP1000 design, this category 

includes the ESBWR, a passive BWR design 

under development by GE. The ESBWR 

RETAINED for 

further screening.
14-161

Technology Description Status

design is not yet certified by the NRC. 

Westinghouse is also considering development 

of a larger passive plant, possibly an AP1600 

(1600 MW). The current passive designs have 

the same environmental characteristics as the 

current fleet of light water reactors.

26. Nuclear Advanced 

Light Water Reactor –

Modular

The economics of the smaller advanced 

modular reactor designs, such as the B&W 

mPower (approximately 125 MW) are unclear. 

Additionally, these designs are years behind the 

evolutionary and passive plants in terms of both 

design development and licensing. They are 

expected to have the same environmental 

characteristics as other nuclear options.

Dropped from 

further screening 

due to development 

status.

27. Solar Thermal 

Parabolic Trough

Solar technologies based on focusing the sun’s 

energy to heat a working fluid work most 

effectively in direct sunlight. Diffuse solar 

insolation due to clouds and haze in the 

Southeast reduces the value of most solar 

thermal applications, and the high capital cost 

and large land area requirements are significant 

concerns. The technology has good 

environmental characteristics. One potential 

application of this technology is to use the 

steam that can be generated from this 

technology to augment the steam generated 

from a conventional fossil power plant, or to 

augment thermal loads in processes such as 

post-combustion carbon capture, giving a 

lower-cost method of utilizing solar energy to 

power.

RETAINED for 

further screening.

28. Solar PV Cost has dropped significantly in recent years, 

getting closer to being competitive on large 

scale with retail rates. Research continues to 

increase efficiency and reduce cost. Issues 

include the site specific solar insolation 

resource and large land area requirements. 

There are some limits to applicability in the 

southeastern U.S. Breakthroughs in PV 

technology could make this a very attractive 

alternative. The technology has excellent 

environmental aspects.

RETAINED for 

further screening.

29. Wind Power Available wind resources in the southeastern 

U.S. are not adequate to currently support 

significant utility scale use of this technology. 

RETAINED for 

further screening.
14-162

Technology Description Status

Advancing wind turbine technologies could 

increase potential.

30. Municipal Solid Waste 

(“MSW”)

MSW generation has been used in some locales 

where landfills are too expensive or 

environmentally unacceptable. Thus, it has 

some potential but is highly site-specific and 

limited in ultimate quantity.

Dropped from 

further screening 

due to limited 

interest and high 

level of 

environmental 

concern.

31. Dedicated Biomass 

(wood, etc.)

Biomass (wood, wood waste, agricultural 

residues) is widely available in the Southeast. 

A dedicated biomass-fired power plant of 

50MW to 100MW in size is feasible. Major 

consideration is obtaining fuel under a longterm contract at a reasonable (and low) price. 

The plant may rely on gasification of biomass, 

followed by a CT to convert the gas to 

electricity. Raw biomass tends to have a high 

transportation cost, due to its low energydensity in raw form. This places an upper limit 

on the size of a dedicated biomass-consuming 

power plant.

RETAINED for 

further screening.

32. Co-fired Biomass or 

Wood Waste

Co-firing of switchgrass and wood waste has 

been demonstrated at several system power 

stations. Co-firing of these materials is now 

routine in AL and MS for green power pricing 

programs. Co-firing at up to 10 percent is 

probably the upper limit with traditional woody 

biomass. Co-firing at higher levels with 

advanced fuels such as pellets and torrefied 

wood is possible, but is potentially detrimental 

to SCR emission reduction system catalysts. 

RETAINED for 

further screening. 

(refer to technology 

1).

33. Landfill Gas Capped landfills produce methane gas through 

anaerobic digestion of the landfill contents. 

The gas has about half the energy of natural gas 

per cubic foot and can be burned in engines or 

co-fired in natural gas boilers or turbines. 

Many environmental advantages with possible 

economic viability are present. A single large 

landfill may provide gas for 7MW max.

RETAINED for 

further screening.

34. Geothermal Geothermal resources in the southeastern U.S. 

are not adequate to support utility scale of this 

technology. Technologies are being monitored 

on a research level for potential niche 

applications.

Dropped from 

further screening 

due to limited 

applicability in 

Georgia Power’s 
14-163

Technology Description Status

and Southern 

Company’s 

territory.

35. Solar Stirling Dish The Dish Stirling engine operates as an 

externally heated piston-driven prime mover. 

In a solar Stirling dish system, a dish is used to 

capture and focus sunlight to provide heat for 

the Stirling engine. As with the parabolic 

trough and other reflector systems, diffuse solar 

insolation due to clouds and haze in the 

Southeast greatly reduces the effectiveness and 

value of solar Stirling dish. This technology 

has good environmental characteristics, but 

applicability is very limited in the southeastern 

U.S.

Dropped due to cost 

uncertainties, level 

of development, 

and limited 

applicability in 

Georgia Power’s 

and Southern 

Company’s 

territory.

36. Solar Central Receiver 

Technology

This technology is commonly referred to as a 

"power tower”, where an array of mirrors is 

focused on a specific area on a tower that 

contains a receiver (boiler) where steam is 

made directly. It works most effectively in 

direct sunlight. Diffuse solar insolation due to 

clouds and haze in the Southeast reduces its 

value, and the high capital cost and large land 

area requirements are significant concerns. 

This technology has good environmental 

characteristics. 

Dropped due to cost 

uncertainties, level 

of development, 

and limited 

applicability in 

Georgia Power’s 

and Southern 

Company’s 

territory.

37. Compact Linear 

Fresnel Reflector

Rows of solar collectors reflect solar radiation 

onto a linear receiver above the solar field in 

which pressurized water is converted into 

steam. It works most effectively in direct 

sunlight. Diffuse solar insolation due to clouds 

and haze in the Southeast reduces its value, and 

the high capital cost and large land area 

requirements are significant concerns. This 

technology exhibits good environmental 

characteristics.

Dropped due to cost 

uncertainties, level 

of development, 

and limited 

applicability in 

Georgia Power’s 

and Southern 

Company’s 

territory.

38. Ocean Energy & 

Hydrokinetic Generation

Ocean energy and hydrokinetic generation 

includes power generation from waves, ocean 

current, tides, and river current. Specific 

research has begun to be conducted in these 

areas defining the resources and developing 

technologies that can utilize these resources. 

They have the potential to negatively affect 

estuarine environments. 

RETAINED for 

further screening 

(hydrokinetic only). 

Ocean energy 

dropped due to 

cost, level of 

development, lack 

of sites, and 

environmental 
14-164

Technology Description Status

considerations.

39. Ocean Thermal 

Generation

The temperature difference between surface and 

deep ocean waters can be used to drive an 

ammonia or other low-temperature power cycle 

to produce power. In most situations, tropical 

locations with deep ocean near shore are 

sought. There are environmental concerns with 

releasing cold bottom water at the ocean surface 

and with the potential for ammonia release.

Dropped due to cost 

uncertainties, level 

of development, 

lack of good sites in 

Georgia Power’s 

and Southern 

Company’s 

territory, as well as 

potential 

environmental 

considerations.
14-165

Table 14.2.2 Candidate Technologies

COAL-FUELED LIQUID/GAS FUELED 

(CONTINUED)

Subcritical Pulverized Coal (2400 psi) Phosphoric Acid Fuel Cell

Supercritical Pulverized Coal (3500 psi) Advanced Fuel Cells

Advanced Ultrasupercritical Pulverized Coal Fuel Cell Combined Cycle

Ultrasupercritical Pulverized Coal Diesel Generator

Atmospheric Fluidized Bed Combustion

Bubbling Bed ENERGY STORAGE

Circulating Bed Pumped Hydro

Pressurized Fluidized Bed Combustion Underground Pumped Hydro

Bubbling Bed Lead Acid Battery 

Circulating Bed Advanced Battery

Advanced Topping Circulating FBC Flywheel 

Integrated Gasification Combined Cycle Compressed Air Energy Storage

Oxygen-Blown

Advanced Air-Blown NUCLEAR

Non-Integrated Coal Gasification Advanced LWR Evolutionary

Combined Cycle Advanced LWR Passive 

Integrated Gasification Fuel Cell Advanced LWR Modular 

Combined Cycle

Magnetohydrodynamics (MHD) RENEWABLES

Solar Thermal Parabolic Trough

LIQUID/GAS FUELED Photovoltaics 

Combustion Turbine Conventional Wind Power 

Combustion Turbine Advanced Municipal Solid Waste

Aeroderivative – Simple Cycle Biomass (Wood, etc.) (Dedicated/cofiring)

Combined Cycle Conventional Landfill gas

Heavy Oil-fired Geothermal 

Combined Cycle Advanced Solar Dish Stirling

G/H technologies Solar Central Receiver

Inlet Air Chilling Compact Linear Fresnel Reflector

Kalina Cycle Ocean Wave and Hydrokinetics

Cascaded Humidified Adv. Turbine (CHAT) Ocean Thermal Generation

Humidified Air Injection (HAI)
14-166

Table 14.2.3 Technologies Selected for Further Screening

COAL-FUELED: ENERGY STORAGE:

 Conv. Pulverized Coal (Subcritical) Pumped Hydro

 Conv. Pulverized Coal (Supercritical) Compressed Air Energy Storage

 Ultrasupercritical Pulverized Coal Advanced Battery

 Oxygen-Blown IGCC

 Air-Blown IGCC NUCLEAR:

 Advanced LWR - Evolutionary

GAS-FUELED: Advanced LWR - Passive

 Combustion Turbine Conventional

 Combustion Turbine Advanced RENEWABLES:

 Combined Cycle Conventional Solar Thermal Parabolic Trough

 Combined Cycle Advanced Photovoltaics

 Phosphoric Acid Fuel Cell Wind Power

 Advanced Fuel Cell Dedicated Biomass

 FCCC Co-fired Biomass/Wood Waste

 Landfill Gas

 Hydrokinetic
14-167

ATTACHMENT 14.3 – SUMMARY OF THE SYSTEM POOLING ARRANGEMENT

Introduction

Georgia Power Company is a member of the Southern Electric System, which consists of the 

Operating Companies. The Operating Companies function as a single, integrated public-utility 

system through adherence to the Southern Company System Intercompany Interchange Contract 

(“IIC”), an agreement on file with the FERC. SCS acts as agent for the Operating Companies in 

the administration of the IIC. The term of the IIC provides for the agreement to continue in 

effect from year-to-year after the effective date subject to termination at any time by mutual 

agreement of all the Operating Companies or subject to termination by an individual Operating 

Company by giving five years advance written notice.

The IIC provides a framework whereby the generating resources of the Operating Companies are 

operated in a coordinated and integrated fashion to economically serve their aggregate firm 

obligations, as well as to engage in shorter term transactions in the wholesale markets. Using 

traditional concepts of economic dispatch, the Pool deploys available generation to satisfy the 

aggregate obligations of the system at any given time in a reliable and economic fashion. The 

IIC also provides for coordinated planning between the Operating Companies and for the sharing 

of temporary surpluses and deficits of capacity. The IIC ensures that the after-the-fact 

accounting associated with joint system dispatch (energy) and reserve sharing (capacity) is 

handled in accordance with the principles set forth in that agreement. It should be noted that the 

coordinated planning process for the four traditional (retail) companies (Mississippi Power, 

Alabama Power, Georgia Power and Gulf Power) has been functionally separated from the 

planning process for Southern Power in the latest IIC. This functional separation does not 

change the manner in which the other four Operating Companies have traditionally conducted 

coordinated planning.

Relationship of the Operating Companies under the IIC

The Southern Company Pool is a coordinated Pool, not a centralized Pool. Although the 

generating facilities of each Operating Company are committed to a centralized economic 

dispatch, each individual Operating Company retains the right and the responsibility for 
14-168

providing the generation and transmission facilities necessary to meet the requirements of its 

customers. Each Operating Company has its own management that reports to its own board of 

directors, with the management and the board of directors of each Operating Company being 

directly responsible for making the decisions that affect that Operating Company and its 

customers. They are also responsible for working with local regulators and adhering to the 

requirements of state law.

Accordingly, each Operating Company has its own distinct characteristics in regard to types of 

generation and load. For example, Alabama Power, Georgia Power and Southern Power bring 

hydroelectric and nuclear generating capacity to the Pool, while the other Operating Companies 

do not. Similarly, the load characteristics of the Operating Companies vary due to the types of 

customers each brings to the Pool. The differing economies within each Operating Company 

territory and/or customer base lead to different load growth rates and load shapes for each 

Operating Company.

The IIC provides for an Operating Committee that consists of one representative of each 

Operating Company and SCS, with the SCS representative acting as a non-voting Chairman. 

The functional separation of certain activities of Southern Power restricts the participation of its 

Operating Committee member in some matters (such as discussions and recommendations 

involving the coordinated planning of the four retail Operating Companies). A unanimous vote 

of the five Operating Company members is required in order to change the IIC.

Interconnections

The Operating Companies are interconnected with 12 non-associated utilities through 61 

different transmission facilities. These transmission lines are operated at voltages of 46 kV, 69 

kV, 115 kV, 161 kV, 230 kV and 500 kV, and include facilities that are operated normally open. 

The non-associated utilities with which the SES is interconnected are shown in Table 14.3.1 

below.
14-169

Table 14.3.1 – Non-Associated Utilities

Florida Power & Light Company Progress Energy - Florida (Duke Energy) 

JEA City of Tallahassee

Duke Energy Corporation (Carolinas) South Carolina Electric & Gas Company

Tennessee Valley Authority South Carolina Public Service Authority

Entergy Corporation Crisp County Power Commission

PowerSouth Energy Cooperative South Mississippi Electric Power Association.

Basic Principles of the IIC

The basic principles of the IIC can be summarized as follows. 

1. Each Operating Company submits its load and generation to the Pool for joint 

commitment and economic dispatch.

2. Energy Principles

a. Each Operating Company retains its lowest cost resources to serve its customers.

b. An Operating Company’s excess energy is then made available to the other 

Operating Companies to serve their customers.

c. An Operating Company is entitled to buy energy from the Pool if the cost is lower 

than energy from its own resources.

d. Energy in excess of that necessary to serve the Operating Companies’ customers 

is marketed by the Pool to the wholesale markets.

3. The IIC provides for coordinated planning among the retail Operating Companies and for 

the sharing among all Operating Companies of temporary surpluses and deficits of 

capacity.

4. Under the IIC, each Operating Company shares in the benefits and pays its share of the 

costs resulting from their coordinated operations.
14-170

Participation in the Southern Company Pool provides benefits to the Operating Companies and 

to their customers. This not only enhances GPC’s ability to provide reliable, low-cost electric 

service to its customers but also to achieve economies of scale in any required investments. 

Benefits of Pool participation include:

(a) Staggering construction of new generating facilities so that each retail 

Operating Company can construct and install the optimum sized 

generating facilities while utilizing economies of scale;

(b) Sharing temporary surpluses and deficits of generating capacity that can 

arise as a result of coordinated planning or other circumstances (e.g., 

staggered construction schedules, variations in load patterns, load forecast 

uncertainties, etc.);

(c) Coordinating scheduled maintenance to provide greater flexibility, 

including major maintenance requiring relatively long unit outages, as 

well as mitigating the cost impact (to customers) of these required 

outages;

(d) Carrying a lower generation planning reserve margin (due primarily to 

system load diversity), which enables each Operating Company to have a 

lower investment in generating resources;

(e) Providing reliable service with shared operating reserve requirements 

(which puts downward pressure on fuel costs);

(f) Access to lower cost energy from other Operating Companies;

(g) Enhanced reliability of electric service through the use of transmission 

interconnections to provide backup service in case of emergencies as well 

as providing the ability to import lower cost energy when available; and,

(h) Acting as a Pool (instead of individual Operating Companies) to identify 

shorter term purchase and sale opportunities in the wholesale markets that 

may be available from time to time.
14-171

Basic Operation of the IIC

The concept of economic dispatch, which seeks to minimize the total system production cost, is 

one of the major benefits of the Pool. The generating assets of all the Operating Companies in 

the Pool are committed and dispatched as a common system without regard to the ownership of 

each generating facility. Subject to operational constraints and reliability considerations, the 

lowest cost generation assets are dispatched during each hour to meet the total needs of the 

customers of all the Operating Companies. The goal of this process is to ensure that the lowest 

cost energy is produced every hour. It also should be noted that each Operating Company retains 

its lowest cost generation to serve that Operating Company’s customers. 

The Pool also interfaces with the wholesale markets on behalf of the Operating Companies for 

both sales and purchases. When the Pool has excess power available, it will pursue wholesale 

sales opportunities for which there is a reasonable expectation that the transaction will result in 

positive net margin for the Operating Companies. There are two primary reasons for the Pool to 

seek purchase opportunities: (1) economics; and (2) reliability. The Pool will pursue purchase 

opportunities from the wholesale markets if such purchases are expected to be more economical 

than system resources (again, subject to operational constraints and system reliability). In the 

event the Pool experiences reliability challenges, then the Pool may seek purchases in response 

to such operating conditions.

Reserve Sharing

As noted in the introduction, the IIC contains capacity provisions, commonly referred to as 

“reserve sharing”, that provide for a sharing of temporary generating capacity surpluses and 

deficits that are a result of coordinated planning or other circumstances. As participants in the 

coordinated operation of the integrated electric system, each Operating Company enjoys the 

same level of service reliability. In any given month, however, one or more Operating 

Companies will have a temporary surplus or deficit of capacity relative to the overall level of 

actual system reserves. Consistent with the goal of sharing in the benefits and burdens of the 

coordinated and integrated electric system, the reserve sharing provisions of the IIC provide for 

the equitable allocation of such temporary surplus or deficit capacity. The resulting purchase 

and sale of capacity is transacted on a monthly basis.
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Reserve sharing is determined by comparing each Operating Company’s load responsibility with 

its respective capacity resources recognized through the coordinated planning process. The 

Operating Companies must own or purchase sufficient capacity (including capacity available for 

load service and that which is unavailable due to forced outage, partial outage, and maintenance 

outage) needed to reliably serve their respective load responsibilities. Capacity above that 

amount is considered reserve capacity, and each Operating Company is responsible for a portion 

of such reserve capacity based upon historical peak load ratios. If an Operating Company’s 

reserve capacity is less than its reserve responsibility, that Operating Company will make reserve 

sharing payments under the IIC for the month.

Each Operating Company develops an annual charge (payments are based on monthly capacity 

worth) based upon the cost of its most recently installed or purchased peaking resource(s). The 

Operating Companies that are “selling” capacity to the Pool will receive a payment from the 

Pool based upon their respective capacity rates. The Operating Companies that are “buying” 

capacity from the Pool will make payments to the Pool based upon the weighted average of the 

capacity rates of the “selling” Operating Companies. In this way, all the buying Operating 

Companies pay the same composite cost in a given month for reserve sharing purposes. By 

definition, the amount by which one or more Operating Companies are “short” (make payments) 

will be equal to the amount by which one or more Operating Companies are “long” (receive 

payments). 

Energy Transactions

Energy transactions within the Pool are accounted for on an hour-to-hour basis, with the 

accounting occurring after-the-fact utilizing the actual flows among the operating companies. 

The actual real-time operation of the system is based upon the concept of economic energy 

dispatch, which through on-line computer control assures that available generation is dispatched 

so as to choose the most economical generation available to serve the total System obligation at 

any given time. An adequate set of lowest-cost generating resources is committed in advance to 

meet the total System obligation, with due regard for generation requirements associated with 

service area protection, voltage control, unit protection, and other operating limitations 

considerations.
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For billing purposes under the IIC, each operating company is deemed to have retained its 

lowest-cost energy resources (most notably hydro and nuclear) to serve its own territorial 

customers, plus whichever of its resources that may have been operating outside of economic 

dispatch for purposes of service area protection or voltage control. To the extent an operating 

company’s generation exceeds its own load obligations, that energy is sold to the pool under the 

IIC. If an operating company’s generation is not equal to or greater than its own load 

obligations, the difference is purchased from the pool. The energy rate for energy sold to or 

purchased from the pool by each operating company is referred to as the Associated Interchange 

Energy Rate and represents the incremental System cost of serving the Operating Companies’ 

aggregate firm obligations. Under the IIC, the determination of which operating companies are 

buying from and which are selling to the pool is made on an hourly basis, and an invoice that 

accounts for these energy transactions is rendered monthly.

Peak-Period Load Ratios

Peak-Period Load Ratios are utilized in the allocation of certain energy and capacity transactions 

by the Pool with non-associated systems, hydro regulation energy losses, increases in cost due to 

hydro regulation, and other allocations provided for in the IIC and the Manual to the IIC.

The Peak-Period Load Ratios for each contract year are based upon the prior year’s actual peakperiod energy in the months of June, July, and August for each Operating Company. The peak 

period is defined to be the 14 hours between 7:00 a.m. and 9:00 p.m. of each weekday, excluding 

holidays. The System peak-period energy is equal to the sum of all the Operating Companies’ 

peak-period energy.

The Peak-Period Load Ratios are determined by dividing each Operating Company’s summation 

of the June, July, and August actual weekday peak-period energy loads by the total System June, 

July and August actual weekday peak-period energy loads.
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ATTACHMENT 14.4 – RESEARCH ACTIVITIES

Research & Environmental Affairs 

Georgia Power as a member of the System is involved in a wide range of research activities and 

programs. These activities can be categorized into five major strategic areas: Environmental 

Issues, Energy Supply Technology, Energy End Use Research, Transmission and Distribution 

and Research & Environmental Management. Each of these areas is composed of a number of 

groups of programs.

Environmental Issues

Environmental Legislation and Regulation Program – Provide scientific and economic analyses 

of policy options, legislation, and international initiatives as well as recommendations for actions 

to achieve environmental goals.

Regulatory Implementation Program – Provide analyses necessary to minimize the cost of 

complying with environmental requirements.

Compliance Strategies and Permitting Program – Develop, maintain and coordinate the 

implementation of system-wide, cost effective environmental and compliance strategies and 

provide direct technical support and coordination of all environmental activities. This program 

seeks environmental permits that clearly meet the intent of regulations and carry out Southern 

Company’s environmental commitment, while balancing operating flexibility, schedules, and 

cost.

Environmental Sciences Research Program – Develop information related to environmental 

effects of the Company’s operations to support Company efforts to make sound science available 

for environmental regulatory policy decisions.
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Environmental Stewardship Program – Develop, implement, and coordinate a comprehensive,

integrated environmental stewardship program and facilitate transparent and productive 

engagement on environmental issues with internal and external stakeholders.

Energy Supply Technology 

Emissions Control Program – Develop technologies and provide strategic research and 

development to facilitate both short and long term environmental compliance decisions.

National Carbon Capture Center - Support technology developers in accelerating development of 

technically and economically viable CO2 capture technologies for enabling coal-based power 

generation to remain a key contributor to providing affordable, reliable, and clean power 

generation and continue optimization of advanced coal-based power generation technologies. 

Advanced Energy Systems - Evaluate and develop new concepts in energy systems; support new 

technological advances in the areas of energy production, use, and supply; and promote a more 

robust relationship with key stakeholders to identify unconventional and future opportunities for 

more valuable integrated energy systems. 

Carbon Capture, Utilization, and Storage - Support the development of economic CO2 capture 

technology; demonstrate secure CO2 storage within the Company territory, engage in stakeholder 

outreach to ensure support for technology deployment, and promote the development of new 

systems and tools, modeling capabilities, and business models to support commercial 

deployment. 

Simple, Combined, and Advanced Cycle Power Research Program - Maximize gas turbine fleet 

availability and performance; analyze, develop, and demonstrate emerging advanced natural gas 

generation concepts for retrofit or greenfield applications, and provide generation technology 

assessment for system planning support. 

Plant and Fuels Enhancements Program - Research, develop, and demonstrate advanced 

technologies that reduce existing plant operating costs or improve reliability; provide solutions to 

highly specialized plant problems that have been screened with regard to risk, probability of 
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success and rate of return and analyze, develop, and demonstrate emerging advanced generation 

concepts for greenfield or retrofit applications. 

Renewable Energy Program - Evaluate current biomass, wind, solar, and other central station and 

distributed generation technologies for renewable energy production; provide technical, 

economic, and environmental research to evaluate, develop, and demonstrate promising future 

renewable technologies; and determine the lowest cost approaches to central station and 

distributed generation renewable technologies.

Energy End Use Research

Industrial Energy Efficiency Program – Bring proven new industrial electrotechnologies, or 

existing technologies with new applications to the market. 

Building Energy Efficiency Program - Identify, assess, and demonstrate new energy efficient 

technologies and software products for application in building design, energy-related heating, 

ventilating, and air conditioning (HVAC), water heating, lighting, appliance, and building 

structure.

Electric Transportation Program – Use internal and external research and development resources 

to support technology evaluation, testing, and demonstration of non-road technologies and 

electric drive vehicles.

Power Quality (“PQ”) Program - Identify, assess, and demonstrate new PQ technologies that will 

increase customer productivity by providing for point-of-use enhanced PQ and assisting 

personnel with troubleshooting and analysis. This program will evaluate other end-use 

technologies and their PQ impacts to the power delivery system.

Transmission and Distribution 

Transmission Lines Program - Deploy and develop tools, technology, and work practices in 

order to further improve the effectiveness of the Company’s transmission system. 

Substations Program - Develop tools and technology to ensure the company’s substations are 

reliable, secure, and intelligent. 
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Distribution Program - Evaluate new technologies, techniques, and concepts to identify proper 

investments that increase safety, reliability, and efficiency.

Transmission Operations and Planning Program - Improve reliability and stability by providing 

technology options to optimize the planning, design, construction, and operation of the 

company’s transmission system.

Research and Environmental Management

EPRI Management and Technology Innovation Program - Ensure that the EPRI research plan is 

in line with Southern Company’s research needs, effectively manage the EPRI-Tailored 

Collaboration program, and maximize the benefits of EPRI membership through effective 

technology transfer. 

Advanced Generation Deployment Program – To support commercialization, deployment and to 

maintain the option of positioning coal based power generation as a key contributor to providing 

affordable, reliable and clean power generation as warranted. 
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(This page is intentionally blank.)
Application for Decertification of Plant Branch 

Units 3 and 4, Plant McManus Units 1 and 2, 

Plant Kraft Units 1-4, Plant Yates Units 1-5, 

Plant Boulevard Units 2 and 3, and Plant Bowen 

Unit 6
1

(This page is intentionally blank.)
2

Application for Decertification of Plant Branch Units 3 and 4, 

Plant McManus Units 1 and 2, Plant Kraft Units 1-4, Plant Yates Units 1-5, 

Plant Boulevard Units 2 and 3, and Plant Bowen Unit 6

1. INTRODUCTION

In accordance with and as supported by Georgia Power Company’s (“Georgia Power” or 

the “Company”) 2013 Integrated Resource Plan (“IRP”), the Company hereby files this 

Application for Decertification of Plant Branch Units 3 and 4, Plant McManus Units 1 and 2, 

Plant Kraft Units 1-4, Plant Yates Units 1-5, Plant Boulevard Units 2 and 3, and Plant Bowen 

Unit 6 (“2013 Decertification Application”) pursuant to O.C.G.A. § 46-3A-3 and Commission 

Rules 515-3-4-.08. The units presented for decertification represent 2,093 megawatts (“MW”) of 

generating capacity and have had a long and distinguished history of service to Georgia Power 

customers and a significant positive impact on the communities in which they operate. Only 

after extensive analysis and evaluation and after exploring a wide range of feasible compliance 

options did the Company determine that retirement and decertification of these units is in the 

best interest of all customers. The Company hereby incorporates by reference all other portions 

of the Company’s 2013 IRP filing into this 2013 Decertification Application. 

2. DECERTIFICATION REQUESTS

2.1 Need for Decertification 

As detailed in Sections 1.1, 1.5, and Section 6 of the Main Document, the projected costs 

to comply with the United States Environmental Protection Agency’s Mercury and Air Toxics 

Standards (“MATS”) rule and other pending environmental regulations have placed significant 

pressure on the economic viability of several of the Company’s fossil generating units, resulting 

in the determination that retirement and decertification is the most cost-effective approach for 

Plant Branch Units 3 and 4, Plant Kraft Units 1-4, Plant McManus Units 1 and 2, and Plant Yates 

Units 1-5. And though the MATS rule and other existing and pending environmental regulations 

are the key drivers, the current forecasts of natural gas prices and the recent economic downturn 

and resulting loss of load have also had a negative impact on the economics of these units. 

While these units have provided significant benefit to customers, the economic analysis now 
3

shows that retirement is in the best interest of all customers. 

Plant Branch Units 3 and 4 are two coal-fired units with a total capacity of 509 MW and 

507 MW respectively and were placed in service in 1968 and 1969, respectively. Plant Kraft 

Units 1-4 are coal-fired units that were placed in service at various times between 1958 and 1971 

and have a total generating capacity of 316 MW. Plant McManus Units 1 and 2 are oil-fired 

steam plants that went in service in 1952 and 1959, respectively, and have 43 MW and 79 MW 

of generating capacity, respectively. Plant Yates Units 1–5 are coal-fired generating units that 

were placed into service at various times between 1950 and 1958 and have 579 MW of total 

generating capacity. The economic analyses for Plant Branch Units 3 and 4, Plant Kraft Units 1-

4, Plant McManus Units 1 and 2, and Plant Yates Units 1-5 are contained in Sections 1.6.2, 

1.6.5, 1.6.7, and 1.6.10 of the Unit Retirement Study in Technical Appendix Volume 2. The 

analysis for each unit shows that it is not beneficial for customers for the Company to invest in 

these units to allow for continued operations.

As detailed in Sections 1.1, 1.5, and Section 6 of the Main Document, the Company is 

also seeking to decertify Plant Boulevard Units 2 and 3 and Plant Bowen Unit 6. Plant 

Boulevard Units 2 and 3 are two oil-fired combustion turbines (“CT”) rated at a capacity of 14 

MW each, and were installed in 1970 along with Unit 1. Both units recently experienced a 

significant equipment failure and the Company’s economic analysis demonstrates that the repairs 

are not in customers’ best interest. The economic analysis supporting the retirement of Plant 

Boulevard Units 2 and 3 can be found in Section 1.6.12 of the Unit Retirement Study. Plant 

Boulevard Unit 1 is not damaged and remains a cost-effective unit for customers, and therefore, 

is recommended for continued operation. The Company has similarly determined that it will be 

economically beneficial for customers to retire Plant Bowen Unit 6. Plant Bowen Unit 6 is a 32 

MW oil-fired CT that is only permitted to operate during non-summer months due to ozone 

nonattainment requirements in the area. The economic analysis supporting the retirement of 

Plant Bowen Unit 6 can be found in Section 1.6.13 of the Unit Retirement Study. 

2.2. Request for Expedited Decertification of Plant Bowen Unit 6

As detailed in Section 1.1 and Section 6 of the Main Document, the Company requests 

expedited decertification of Plant Bowen Unit 6 by no later than April 16, 2013. The Company 
4

seeks decertification for Unit 6 due to the unfavorable economics of continued operation. In 

addition, Plant Bowen Unit 6 is located in close proximity to the planned baghouse construction 

activity for Units 3 and 4. Therefore, the Company plans to remove the unit from its current 

location, pending Commission approval of the Company’s decertification request.

In light of the unfavorable economics and the proximity of the unit to the construction 

activity, the Company proactively sought sale opportunities for the generator and was able to 

reach an agreement to sell the unit (which agreement is contingent on Commission approval of 

decertification). Due to the current construction schedule for the Plant Bowen Units 3 and 4 

baghouses, Unit 6 needs to be removed no later than June 1, 2013, and the purchase agreement 

thus requires that the buyer remove the unit by May 31, 2013. However, in order to allow the 

buyer sufficient time to meet the May 31, 2013 removal date, the purchase agreement conditions 

the sale on Commission approval of the decertification of the unit by April 16, 2013. If 

decertification is not achieved by April 16, 2013, the purchase agreement will be terminated by 

Georgia Power, and the deposit will be returned to the potential purchaser. Therefore, the 

Company requests expedited decertification of Plant Bowen Unit 6 by no later than April 16, 

2013. Expedited decertification is appropriate in this case because of the clarity of the economic 

analysis and because of the logistical benefits of the sale in connection with the construction 

schedule of the baghouses for Units 3 and 4. Furthermore, proceeds from the sale will eliminate 

the remaining net book value of Unit 6.

Additional financial details regarding Plant Bowen Unit 6 and a copy of the purchase 

agreement are provided in the Selected Supporting Information in Technical Appendix Volume 

2. The buyer is unaffiliated with Georgia Power or any of its affiliates.
5

2.3 Analysis of Transmission Impacts

In accordance with the Commission’s order in Docket No. 31081, the Company 

performed an analysis of the results of the requested decertifications on transmission facilities. 

The transmission facilities added, modified or avoided as a result of this decertification request 

are as follows: 

Plant Project Name Date Impact

Plant McManus Units 1 

and 2

McManus - West Brunswick 

115kV Rebuild

2014 Project no longer 

needed if Plant 

McManus Units1 and 2 

are retired

Plant Kraft Units 1-4 McIntosh-Blandford-Meldrim 

230kV BLK & WHT 

Reconductor

2014 Projects needed if Plant 

Kraft Units 1-4 are 

retired

Boulevard 230/115kV Project 2015

Plant Kraft 115/46kV #2 

Transformer Project

2015

Plant Yates Units 1-5 Dyer Road 230/115kV 2015 Projects needed if Plant 

Yates 1-5 are retired Corn Crib 230/115kV 

Substation

2018

Projects not associated 

with a single plant 

retirement 

North Tifton Second 

500/230kV Auto

2014 Projects needed due to 

plant retirements but not 

associated with a single 

plant retirement Jasper - Pine Grove Primary 

115kV Rebuild

2014

First Avenue - Victory Drive 2015

Raccoon Creek - Thomasville 

230kV Reconductor (GPC 

Portion)

2015

Douglas - Pine Grove 230kV 

Project

2015
6

2.4 Cost Recovery

In connection with the requested decertifications, the Company requests that the 

Commission approve the following: 

1) Reclassification of the remaining net book values of Plant Branch Units 3 and 4 and 

Plant Boulevard Units 2 and 3 as of their respective retirement dates to regulatory 

asset accounts and the amortization of such regulatory asset accounts ratably over a 

period equal to the respective unit’s remaining useful life approved in Docket No. 

31958;

2) Amortization of approximately $38 million of Plant Branch Units 3 and 4 and 

approximately $14 million of Plant Yates Units 6 and 7 environmental construction 

work in progress (“CWIP”) (which has been reclassified as a regulatory asset in 

accordance with the Commission’s Order in Docket No. 31958) ratably over a three 

year period beginning January 2014; 

3) Reclassification of any unusable material and supplies (“M&S”) inventory balance 

expected to be remaining at the unit retirement dates to a regulatory asset as identified 

in accordance with the Commission’s Order in Docket No. 31958 for recovery over a 

period to be determined by the Commission in the Company’s next base rate case 

following the unit retirements; and

4) In the event the Commission does not approve the expedited decertification of Plant 

Bowen Unit 6, the Company requests the reclassification of the remaining net book 

value of Plant Bowen Unit 6 as of its respective retirement date to a regulatory asset 

account and the amortization of such regulatory asset account ratably over a period 

equal to the unit’s remaining useful life approved in Docket No. 31958. 

3. CONCLUSION

As set forth in the Company’s 2013 IRP, Georgia Power’s current supply-side plan, 

which incorporates the requested decertifications contained herein, is sufficient to provide costeffective and reliable sources of capacity and energy through 2015 and beyond. The known and 

reasonably expected effects of these retirements on the Company’s 2013 IRP are described more 

fully in the Main Document and the Technical Appendices. The requests contained in this 2013 

Decertification Application are in the public interest and substantially comply with the relevant 

Commission rules. Therefore, the Company requests that the Commission approve the 

following: 

1) Decertification of Plant Branch Units 3 and 4, Plant Yates Units 1-5, and Plant 

McManus Units 1 and 2 effective by the MATS compliance date of April 16, 2015; 
7

2) Decertification of Plant Kraft Units 1-4 one year past the MATS compliance date (by 

April 16, 2016); 

3) Decertification of Plant Boulevard Units 2 and 3 effective as of the date of the final 

order in this proceeding; 

4) Expedited decertification of Plant Bowen Unit 6 by April 16, 2013; and 

5) The related cost recovery as detailed in Section 2.4.