NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

Technical Report

NREL/TP-6A20-72003

February 2019

Existing and Potential Corporate 

Off-Site Renewable Procurement 

in the Southeast

Jenny Heeter, Jeffrey J. Cook, and Jennifer Sauer

National Renewable Energy Laboratory
NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

Technical Report

NREL/TP-6A20-72003

February 2019

Existing and Potential Corporate 

Off-Site Renewable Procurement 

in the Southeast

Jenny Heeter, Jeffrey J. Cook, and Jennifer Sauer

National Renewable Energy Laboratory

Suggested Citation

Heeter, Jenny, Jeffrey J. Cook, and Jennifer Sauer. 2019. Existing and Potential Corporate 

Off-Site Renewable Procurement in the Southeast. Golden, CO: National Renewable 

Energy Laboratory. NREL/TP-6A20-72003. https://www.nrel.gov/docs/fy19osti/72003.pdf.
NOTICE

This work was authored by the National Renewable Energy Laboratory, operated by Alliance for Sustainable 

Energy, LLC, for the U.S. Department of Energy (DOE) under Contract No. DE-AC36-08GO28308. Funding 

provided by the U.S. Department of Energy Office of Energy Efficiency and Renewable Energy Solar Energy 

Technologies Office. The views expressed herein do not necessarily represent the views of the DOE or the U.S. 

Government.

This report is available at no cost from the National Renewable 

Energy Laboratory (NREL) at www.nrel.gov/publications.

U.S. Department of Energy (DOE) reports produced after 1991 

and a growing number of pre-1991 documents are available 

free via www.OSTI.gov.

Cover Photos by Dennis Schroeder: (clockwise, left to right) NREL 51934, NREL 45897, NREL 42160, NREL 45891, NREL 48097, 

NREL 46526.

NREL prints on paper that contains recycled content.
iv

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Acknowledgments

This work was funded by the U.S. Department of Energy’s (DOE’s) Office of Energy Efficiency 

and Renewable Energy. The authors thank the Solar Energy Technologies Office for its support 

of this work.

For their thoughtful review of the document, the authors thank Lori Bird, Jaquelin Cochran, and

Gian Porro of the National Renewable Energy Laboratory (NREL). We also thank Lisa M. Jonas

for editorial support and John Frenzl for graphics support.

We thank the following individuals for participating in market interviews: Liz Philpot (Alabama 

Power); Robert Flores (Berry Global); Andy Smith (Cisco Systems); Jayant Gour (CustomerFirst 

Renewables); Chris Quarterman and Evan Riley (Cypress Creek Renewables); Jamie Billingsley,

Stan Blackwell, and Robert Trexler (Dominion Energy); Emily Felt and Paul Halstead (Duke 

Energy); John Morrison (Ecoplexus); Wilson Ballard and Brooke Starr Haman (Georgia Power);

Rhonda Alexander (Gulf Power); Linda Acker (Mississippi Power); Deb Roepke (National Rural 

Electric Cooperative Association); Diane Huis (North Carolina Electric Cooperative); Eric 

Udelhofen (One Energy); Jonathan Reinbold (Organic Valley); Matt Diamond (PowerSouth 

Energy Cooperative); Mark Ragase (Procter & Gamble); Kirk Myers (REI); Jason Peters 

(Seminole Electric Cooperative); Matt Beasley and Reagan Farr (Silicon Ranch Inc.); John 

Raftery (South Carolina Electric and Gas Company); and Amanda Garcia and Katie Ottenweller 

(Southern Environmental Law Center). This report does not necessarily reflect the viewpoint of 

any one interviewee or their specific company.

We also appreciate the state agency staff members who provided information on corporate 

renewable procurement pathways in their jurisdictions: Patricia Smith and Chad Mason 

(Alabama PSC), Cayce Hinton (Florida PUC), Jamie Barber (Georgia PSC), Vicki Munn 

(Mississippi PSC), Sam Watson (North Carolina Utilities Commission), Deborah Easterling 

(PSC of South Carolina), and Joe Shirley (Tennessee PUC). 
v

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

List of Acronyms

AEP American Electric Power

C&I commercial and industrial

DOD U.S. Department of Defense

DOE U.S. Department of Energy

FERC Federal Energy Regulatory Commission

FP&L Florida Power & Light

G&T generation and transmission

GPSC Georgia Public Service Commission

IOU investor-owned utility

ISO independent system operator

LCOE levelized costs of energy

MBR market-based rate

MISO Midcontinent Independent System Operator, Inc.

MIT Massachusetts Institute of Technology

NCUC North Carolina Utilities Commission

NRECA National Rural Electric Cooperative Association

NREL National Renewable Energy Laboratory

PJM PJM Interconnection

PPA power purchase agreement

PURPA Public Utility Regulatory Policies Act

PV photovoltaic

QF qualifying facility

RE renewable energy

REC renewable energy credit

REDI Renewable Energy Development Initiative

RTO regional transmission organization

SCE&G South Carolina Electric & Gas Company

SLED State and Local Energy Data

TVA Tennessee Valley Authority

UMMEG Upper Midwest Municipal Energy Group

WWF World Wildlife Fund
vi

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Executive Summary

As corporations, public agencies, and other institutions make commitments to use renewable 

energy, they increasingly are turning to purchase renewable energy from off-site locations, in 

addition to on-site systems. To date, most off-site renewable energy has been purchased from the 

midsection of the country (in Texas and Oklahoma) where low-cost wind power is available, and

enabling purchasing policies and programs exist for corporate buyers. 

This analysis focuses on the Southeast, where corporate off-site renewable purchasing 

historically has been limited. This report uses the term “corporate” to refer to non-utility offtakers. This includes government, non-profit, higher education, and other institutions. The 

analysis identifies about 730 MW of renewables contracted by corporates as of the end of 2017.i

Contracting has been done through four pathways: (1) Utility partnerships, including green 

tariffs and bilateral contracts; (2) community solar; (3) owning qualifying facilities under the 

federal Public Utility Regulatory Policies Act (PURPA); and (4) retail choice and power 

purchase agreements (PPAs) (Figure ES-1). Utility partnerships resulted in 55% of the capacity, 

at 405 MW.

Figure ES-1. Contracted off-site corporate renewable capacity in the Southeast, by procurement 

option.

This contracted renewable energy (RE) capacity does not meet the renewable energy demand by

corporates with electricity load in the Southeast. We gathered data from corporate-owned 

entities, higher education institutions, and local governments having renewable energy targets. 

This sample renewable energy demand is an underestimate because we were limited to data 

 

i This estimate was identified by a review of a variety datasets from the Energy Information Administration, SNL 

Financial Inc., and Bloomberg New Energy Finance among others. The estimate was also vetted through discussions 

with electric service providers and corporates across the Southeast. We include Georgia Power’s green tariff is 

“contracted” in 2017 in our figures, since that is when the program was launched, however, individual off-taker 

contracts were signed in 2018.

 -

 50

 100

 150

 200

 250

 300

 350

 400

 450

Corporate-Owned

PURPA Project

Utility Partnership Off-Site PPAs Community Solar

MW of contracted capacity

Alabama Florida Georgia Mississippi North Carolina South Carolina Tennessee
vii

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

supplied directly by corporations, via Second Nature, and data drawn from the Sierra Club’s 

Ready for 100 campaign. Current and planned capacity meet 21% of our sample’s renewable 

energy demand in the Southeast. 

In states with the greatest identified corporate renewable energy demands (North Carolina, 

Georgia, and Florida), contracted capacity could provide 36%, 43%, and 3%, respectively 

(Figure ES-2). These plans leave about 4 million MWh of unmet renewable energy demand in 

the Southeast; if solar were to serve that demand, it would result in more than 2,000 MW of new 

solar projects (assuming a 22% average capacity factor). 

Figure ES-2. Renewable energy demand and contracted renewable energy capacity in the 

Southeast.

Unmet renewable energy demand could be met by expansion of existing pathways, e.g. new 

utilities offering a green tariff or developing bilateral contracts. The unmet renewable energy 

demand could also be met via emerging pathways. We identify four emerging pathways with 

potential in the Southeast: 1) a large-scale land lease for renewables, 2) a PURPA-based 

contract-for-differences, 3) market-based utility rates with a separate renewable energy contract 

for a project in an RTO/ISO territory, and 4) subscription solar at scale, with corporate anchor 

tenants. 

73%

3%

43%

0%

36%

7% 9%

0%

10%

20%

30%

40%

50%

60%

70%

80%

 -

 500,000

 1,000,000

 1,500,000

 2,000,000

 2,500,000

AL FL GA MS NC SC TN

MWh

RE Demand Existing RE Pathways Percent met by existing options
viii

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Table of Contents

1 Introduction........................................................................................................................................... 1

2 Demand for Renewable Energy in the Southeast ............................................................................. 3

3 Barriers to Procuring Off-Site Renewables in the Southeast .......................................................... 7

3.1 Renewable Energy Pricing............................................................................................................ 7

3.2 Off-Site Renewable Procurement Options.................................................................................... 8

4 Procurement Pathways...................................................................................................................... 11

4.1 Utility Partnerships: Renewable Contracts.................................................................................. 11

4.1.1 Market Status ................................................................................................................. 11

4.1.2 Case Study: Georgia Power’s Green Tariff.................................................................... 15

4.1.3 Outlook........................................................................................................................... 16

4.2 Community Solar ........................................................................................................................ 18

4.2.1 Market Status ................................................................................................................. 19

4.2.2 Case Study: Corporate Access to Cooperative Utility Community Solar Programs...... 22

4.2.3 Outlook........................................................................................................................... 24

4.3 Competitive Market Access........................................................................................................ 24

4.3.1 Market Status ................................................................................................................. 25

4.3.2 Case Study: Conetoe II Solar Project............................................................................. 27

4.3.3 Outlook........................................................................................................................... 28

4.4 Public Utility Regulatory Policies Act Qualifying Facilities...................................................... 28

4.4.1 Market Status ................................................................................................................. 29

4.4.2 Case Study: The Evolution of North Carolina PURPA Policies.................................... 33

4.4.3 Outlook........................................................................................................................... 35

4.5 Emerging Pathways..................................................................................................................... 36

4.5.1 Model 1. Large-Scale Land Lease for Renewables........................................................ 36

4.5.2 Model 2. PURPA-Based Contract-for-Differences Model ............................................ 36

4.5.3 Model 3. Market-Based Rates and Separate Contract with an Off-Site Project in 

RTO/ISO Territory......................................................................................................... 37

4.5.4 Model 4. Subscription Solar at Scale, with Corporate Anchor Tenants......................... 38

5 Summary and Market Outlook........................................................................................................... 40

6 References .......................................................................................................................................... 44

 
ix

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List of Figures

Figure ES-1. Contracted off-site corporate renewable capacity in the Southeast, by procurement option.. vi

Figure ES-2. Renewable energy demand and contracted renewable energy capacity in the Southeast......vii

Figure 1. Off-site renewables in the Southeast. ............................................................................................ 1

Figure 2. Renewable energy demand (MWh, percentage) in the Southeast, by end-user segment. ............. 4

Figure 3. Renewable energy demand in the Southeast, by state and type of end user.................................. 4

Figure 4. Renewable energy demand (MWh, percentage) in the Southeast, by end-user segment 

(municipal load only)............................................................................................................... 6

Figure 5. Renewable energy demand in the Southeast, by state and end-user segment (municipal load 

only). ........................................................................................................................................ 6

Figure 6. Average commercial retail prices by state, 2008–2017................................................................. 7

Figure 7. Retail sales to all customers, by utility type and state (2016). ...................................................... 8

Figure 8. Contracted renewable energy capacity by state and utility partnership type............................... 12

Figure 9. Annual utility partnership contracted capacity by company in the Southeast............................. 13

Figure 10. Contracted renewable capacity at Southeast military installations by state. ............................. 17

Figure 11. Community solar capacity installed by year and state............................................................... 20

Figure 12. Cooperative utility community solar deployment as compared to other utilities in the 

Southeast. ............................................................................................................................... 22

Figure 13. Corporate customer eligibility in cooperative utility community solar projects in the Southeast.

................................................................................................................................................ 23

Figure 14. Offsite financial PPAs contracted in North Carolina by year and off-taker.............................. 26

Figure 15. Small power-producer qualifying facility capacity by state and technology through 2016. ..... 30

Figure 16. Corporate renewable PURPA capacity by technology type in the Southeast............................ 30

Figure 17. Total qualifying facilities by year in the state of North Carolina. ............................................. 33

Figure 18. Large-scale land lease for renewables. ...................................................................................... 36

Figure 19. PURPA-based contract for differences...................................................................................... 37

Figure 20. Market-based rates and separate contract-for-differences with an off-site project in RTO/ISO 

territory................................................................................................................................... 38

Figure 21. Market-based rates and separate contract with an off-site project in RTO/ISO territory.......... 39

Figure 22. Contracted off-site corporate renewable capacity in the Southeast, by procurement option..... 40

Figure 23. Contracted off-site corporate renewable capacity in the Southeast, by state............................. 41

Figure 24. Renewable energy demand and contracted renewable energy capacity in the Southeast......... 42

Figure 25. Contracted and planned future capacity by year and state......................................................... 42

List of Tables

Table 1. Number of Sites Represented in Data Sample................................................................................ 5

Table 2. Summary of Policies to Support Off-Site Corporate Procurement in the Southeast .................... 10

Table 3. Key Benefits and Challenges of Utility Partnerships.................................................................... 11

Table 4. Comparison of Southeastern Utility Partnerships......................................................................... 14

Table 5. Military Partnerships by State, Project Host, and Year ................................................................ 17

Table 6. Key Benefits and Challenges of Community Solar...................................................................... 19

Table 7. Comparison of Selected Community Solar Programs Across the Southeast................................ 20

Table 8. Key Benefits and Challenges of Off-site PPAs ............................................................................ 25

Table 9. Key Benefits and Challenges of PURPA Qualifying Facilities.................................................... 29

Table 10. Comparison of Select PURPA Rates by Largest Electric Retailer in Each State ....................... 32
1

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

1 Introduction

Corporations, public agencies, and other institutions have made significant commitments to use

renewable energy. To meet these commitments, and other objectives, corporates are turning to 

off-site renewable energy purchasing.1 To date, most off-site renewable energy purchasing has 

been concentrated in the midsection of the country (in Texas and Oklahoma) where low-cost 

wind power is available, and supportive purchasing policies and programs exist for corporate 

buyers. As of July 2017, more than 8,100 MW of off-site renewables had been contracted by 

corporates under a power purchase agreement (PPA) structure (Heeter et al. 2017). In other 

regions of the country, off-site renewable energy purchasing has been more limited. In the 

Southeast, about 740 MW of renewables have been contracted by corporates, as of the end of 

2017 (Figure 1).

Figure 1. Off-site renewables in the Southeast.

The limited off-site corporate renewable energy purchasing in the Southeast, defined herein as 

the seven states highlighted in Figure 1 (Alabama, Florida, Georgia, Mississippi, North Carolina, 

South Carolina, and Tennessee), is a result of policy, market, and utility context. This report 

explores the current status of off-site renewable corporate purchasing in the Southeast, examines

corporate renewable energy market potential, and discusses new ways that corporates and 

utilities could facilitate market expansion. The report uses data gathered on corporate electricity 

consumption and goals and over 25 interviews with corporate, regulatory, and utility personnel. 

The report is structured as follows.

 

1 This report uses the term “corporate” to refer to non-utility off-takers, including government, non-profit, higher 

education, and other institutions.
2

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

• Section 2 outlines the results of the survey of corporations with renewable energy 

objectives and their related load in the Southeast. 

• Section 3 discusses the unique barriers and challenges that corporate customers face in 

the Southeast. 

• Section 4 describes key off-site procurement pathways that are available, or could be 

adopted in the Southeast, including the following.

o Green tariffs and bilateral contracts that allow a corporate customer to enter into 

an agreement with their utility to procure renewable energy from a utility-owned 

or utility-managed project with an established long-term rate.

o Community solar that allows organizations to purchase a share of an off-site solar 

array and receive bill credits based on the electricity production of their share.

o Qualifying facility that allows a developer—including a corporate customer—to 

build a renewable energy project and be compensated for electricity generation at 

the utility’s avoided cost rate, as allowed under the federal Public Utility 

Regulatory Policies Act (PURPA). 

o Retail choice that allows customers to choose their electricity supplier—

potentially a supplier that offers a renewable energy option or the ability to 

facilitate a power purchase agreement. These opportunities are limited in the 

Southeast.

o Power purchase agreements that permit a corporate customer to enter into a 

contract for renewable projects securing the rights to the generation and 

environmental attributes.

o Potential new models, such as new procurement models, that are built on existing 

examples and might have potential in the Southeast.

• Section 5 provides a summary of Southeast procurement options by state and an 

assessment of the overall market outlook.

• Section 6 provides a conclusion and pathways for future work.
3

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2 Demand for Renewable Energy in the Southeast

Renewable energy demand in the Southeast is derived from corporations, cities, and highereducation institutions. NREL gathered data directly from corporations, and estimated renewable 

energy demand from cities and higher-education institutions using the methods described in Text 

Box 1. Because these data are only a sample of institutions with renewable energy commitments, 

the estimated demand for renewable energy in the Southeast can be viewed as a lower-bound 

estimate.

We identified nearly 29 million MWh of load in the Southeast that is associated with a renewable 

energy commitment (Figure 2). By comparison, national voluntary market renewable energy 

sales in 2016 totaled 95 million MWh (O’Shaughnessy et al. 2017). The vast majority of our 

sample renewable energy demand in the Southeast is attributed to cities and counties making a 

100% renewable energy commitment (23 million MWh, 79%).2 The remaining demand is split 

roughly evenly between corporations (3.3 million MWh, 12%) and higher education (2.7 million 

MWh, 9%). 

 

2 While in the rest of the report we refer to all non-utility offtakers as “corporates”, in this section we provide data 

segmented by cities and counties, higher education institutions, and corporations. 

Text Box 1. Gathering Data on Renewable Demand in the Southeast

We received or gathered data from 19 companies, 46 higher-education institutions, and 9 cities or 

counties with renewable energy commitments. 

To assess the demand for renewable energy from corporations, NREL created a data questionnaire 

and worked with the World Wildlife Fund (WWF) to circulate it to members of their Buyers’ 

Principles (2018), a group of about 70 corporations that are committed to pursuing renewable 

purchasing. NREL and WWF received responses from 19 companies that had electricity load in the 

study area, including from IT companies, manufacturing companies, retailers, and others.

We used data from Second Nature to estimate renewable energy demand from higher-education 

institutions. Higher-education institutions that are signed on to Second Nature commitments provide 

Second Nature with data on their electricity consumption and renewable energy purchases. This 

dataset includes 46 colleges or universities in our study area.

To understand demand for renewable energy from cities, NREL used city and county renewable 

energy commitments from the Sierra Club’s Ready for 100 campaign, paired with data from the U.S. 

Department of Energy’s (DOE) State and Local Energy Data (SLED) platform. SLED contains 

estimates of city electricity consumption. We estimated municipal electricity consumption at 2% of 

the city-wide electricity consumption.
4

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Figure 2. Renewable energy demand (MWh, percentage) in the Southeast, by end-user segment.

Florida, Georgia, and North Carolina lead the Southeast in commitments to renewable energy, 

with more than 7 million MWh in each state (Figure 3). Demand in these states is driven by the 

cities with renewable energy commitments. In Florida, this includes the cities of Orlando, 

St. Petersburg, and Sarasota. In Georgia, city demand is from Atlanta as well as Clarkston. Two 

of North Carolina’s counties—Buncombe and Orange—have commitments, along with the city 

of Hillsborough, which is located in Orange County. We separate “community load” from 

“municipal load” in recognition that most cities do not control the source of electricity for their 

community. We estimate “municipal load” as 2% of each city’s total electricity consumption.

Figure 3. Renewable energy demand in the Southeast, by state and type of end user.

3,337,472 

12%

2,719,777 

9%

23,164,200 

79%

Corporate Higher Education Cities—Total

 -

 1,000

 2,000

 3,000

 4,000

 5,000

 6,000

 7,000

 8,000

 9,000

 10,000

AL FL GA MS NC SC TN

Annual RE Demand 

(thousands of MWh)

Corporate Higher Education Cities—Community Load Cities—Municipal Load
5

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Although the largest volume of demand is concentrated in Florida, Georgia, and North Carolina, 

the states with the most sites interested in renewable procurement were Florida, North Carolina, 

and South Carolina (Table 1).

Table 1. Number of Sites Represented in Data Sample

Corporate Sites

Higher 

Education Sites

Cities or 

Counties Total Sites

AL 7 0 0 9

FL 243 7 3 261

GA 81 4 2 99

MS 9 1 0 14

NC 86 5 3 114

SC 95 2 1 105

TN 26 3 0 10

TOTAL 547 22 9 612

A big driver for renewable energy demand on a volumetric basis in the Southeast is

commitments by cities and counties. Although cities and counties are making renewable energy 

commitments, unless the city operates a community choice aggregation or has a municipal 

utility, it does not have direct control over the electricity supply for its community. Other than

Orlando, Florida—which has a municipal utility—none of the cities or counties in the study area 

have direct control over their electricity supply. Focusing only on consumption by the city’s 

municipal facilities, instead of examining the entire community’s electricity consumption, we 

identify 6.5 million MWh of load in the Southeast associated with a renewable energy goal 

(Figure 4). In this case, municipal demand is only 7% of the total (0.5 million MWh), corporate 

demand is more than half (51%, 3.3 million MWh), and higher-education demand is 42% 

(2.7 million MWh). 
6

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Figure 4. Renewable energy demand (MWh, percentage) in the Southeast, by end-user segment 

(municipal load only).

When considering only municipal load instead of the electricity consumption by the entire 

community, North Carolina, Georgia, and Florida still see the greatest levels of renewable energy 

demand (though in different order) (Figure 5). Alabama, Mississippi, South Carolina, and 

Tennessee have minimal demand compared to the other states.

Figure 5. Renewable energy demand in the Southeast,

by state and end-user segment (municipal load only).

3,337,472 

2,719,777 51%

42%

463,284 

7%

Corporate Higher Education Cities—Municipal Load

 -

 200

 400

 600

 800

 1,000

 1,200

 1,400

 1,600

 1,800

 2,000

AL FL GA MS NC SC TN

Annual RE Demand 

(thousands of MW)

Corporate Higher Education Cities—Municipal Load
7

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3 Barriers to Procuring Off-Site Renewables in the 

Southeast

Although significant renewable energy demand exists in the Southeast, renewable energy pricing 

and procurement options can create barriers to procuring off-site renewables there. This section 

reviews two barriers to off-site corporate renewable purchasing in the Southeast: pricing and 

existing procurement options.

3.1 Renewable Energy Pricing 

Historically, compared to the standard utility mix, the cost to corporates to purchase exclusively 

wind and solar has been greater in the Southeast than in other parts of the country. This is driven 

by two factors: (1) the comparatively low retail electricity rates in the Southeast, and (2) the lessfavorable technical potential for some renewable resources, particularly for on-shore wind. 

Average commercial retail prices in the Southeast, although trending upward generally, remain 

for the most part below the U.S. commercial average (Figure 6). The highest rates in the region 

are in Alabama, which tracks at or slightly more than the U.S. average. Rates in North Carolina 

consistently have been the lowest in the region. 

Figure 6. Average commercial retail prices by state, 2008–2017.

Source: Energy Information Administration 2018a

If retail rates are low, then—to provide a cost-effective purchase—the cost of renewable energy 

also must be low. Although some organizations, such as those with large amounts of available 

capital, may be willing to spend more than business-as-usual prices on a renewable energy 

purchase, most want some cost savings or cost parity compared to what they currently pay, at 

least over the term of the renewable energy contract. Even though renewable energy costs are 

declining nationally, the Southeast remains one of the highest-cost regions, according to Lazard’s 

0

2

4

6

8

10

12

14

20012002200320042005200620072008200920102011201220132014201520162017

Average Commercial Retail 

Electricity Prices (cents/kWh)

Southeast Range United States Average Southeast Average
8

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

solar and wind levelized costs of energy (LCOE) estimates (Lazard 2018). Cost in the Southeast 

ranges from $59/MWh to $228/MWh. (These regional variations are based only on the capacity 

factor in the region and do not consider other variables—such as transmission constraints—that 

could increase costs.) For wind, the Southeast is the highest LCOE region, at $47/MWh to 

$75/MWh.

3.2 Off-Site Renewable Procurement Options

Although some policies and practices enable off-site renewables in the Southeast, the support 

varies by state and utility (Table 2). In general, policy support is less common than it is in other 

regions of the country (see Heeter et al. 2017 for a review of policies on the national level)

Because customers in the Southeast, by and large, do not have competitive market access, they 

rely on their utility to facilitate off-site renewable options. The Southeast is dominated by large, 

investor-owned monopoly utilities (IOUs), with the exception of Tennessee—where the

Tennessee Valley Authority is the dominant utility (categorized as “municipal”) (Figure 7). In 

other southeast states, IOUs serve more than half of retail sales, cooperatives serve less than 

20%, and municipals serve the remaining portion.

Figure 7. Retail sales to all customers, by utility type and state (2016).

Source: Energy Information Administration 2017

Some utilities in the Southeast are beginning to offer options for off-site procurement. The 

program driving the most off-site corporate procurement in the Southeast is the utility 

partnership, either via bilateral contracts or green tariff development. In theory, these programs 

could be developed in any of the Southeastern states. Four of the seven states in the study region 

have utilities that have either implemented a bilateral contract or developed a green tariff. 

Although the structure of these partnerships heavily influences whether corporates use the 

program, each of the four states with activity has seen renewable deployment under this pathway.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

AL FL GA MS NC SC TN

Percent of Retail Sales

Investor Owned Cooperative Municipal
9

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Community solar programs are the next most common, though typically are not at the scale 

needed by corporates or even large institutions such as colleges and local governments. North 

Carolina is the only state to have mandated community solar (for some utilities). Utilities, 

however, have voluntarily offered programs in Florida, Georgia, South Carolina, and Tennessee. 

Some of the programs developed have a relatively low maximum subscription size (e.g., 1 MW), 

and the value proposition (the subscription price minus the compensation for the subscription’s 

production received) might not result in a net savings to the subscriber, making these programs 

less favorable to corporates and large institutions (assuming these entities are eligible).

Under PURPA, which allows a developer—including a corporate customer—to build a 

renewable energy project and be compensated for electricity generation at the utility’s avoided 

cost rate, most states (aside from North Carolina) provide policies that only support short-term 

contracts and pay low avoided cost rates. In some cases, pricing is variable year to year, adding 

uncertainty to project financing (Table 2)

Finally, most states in the Southeast do not provide any competitive market access, thus 

preventing use of the most favorable option for large corporates—the off-site PPA. Georgia 

offers retail choice for new electricity customers with loads equal to or greater than 900 kW, but 

Georgia requires the customers to remain with the service provider. No competitive suppliers 

were supplying load in Georgia in 2016, perhaps due to this limitation.
10

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Table 2. Summary of Policies to Support Off-Site Corporate Procurement in the Southeast

State

Utility 

Partnerships

Community

Solar PURPA

Competitive 

Market Access

Alabama Yes No supportive 

policies or utility 

projects

Policy in place; short 

contracts only

No

Mississippi Possible, but 

none yet

No supportive 

policies or utility 

projects

Unknown/negotiated 

with utility

No*

Tennessee Yes No supportive 

policies

but utility projects

Policy in place; 5-year 

contracts with rates 

set monthly

No*

South Carolina Possible, but 

none yet

Supportive policy 

(municipalities, 

churches, and 

schools only) and 

utility projects

Policy in place; low 

avoided cost rates

No

Georgia Yes No supportive 

policies

but utility projects

Policy in place; low 

avoided cost rates;

term not specified

Yes

Florida Possible, but 

none yet

No supportive 

policies

but utility projects

Policy in place; 

contract term not 

specified

No

North Carolina Yes Enabling policy and 

utility projects

Supportive policy No*

* Projects located in PJM Interconnection (PJM) territory located in North Carolina or Tennessee could sell 

into PJM and facilitate a financial power purchase agreement. Projects located in Midcontinent Independent 

System Operator, Inc. (MISO) territory in Mississippi could sell into MISO and facilitate a financial power 

purchase agreement.
11

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4 Procurement Pathways

This section reviews pathways for corporate procurement of off-site renewables in the Southeast. 

The pathways considered are: utility partnerships (bilateral contracts and green tariffs), 

community solar, competitive market access (including off-site PPAs), and the development of 

qualifying facilities under PURPA. Each subsection includes a definition of the pathway, 

benefits and challenges of the pathway, its market status, a case study, and the market outlook.

At the end of this section are examples of new or emerging pathways for corporate procurement 

of off-site renewables in the Southeast.

4.1 Utility Partnerships: Renewable Contracts

In the Southeast, corporate customers have had the most success leveraging utility partnerships 

(bilateral contracts and green tariffs) to support their renewable energy objectives. This section 

describes these utility partnerships benefits and challenges (Text Box 2) and their market status. 

Also included is a case study of Georgia Power’s green tariff program and a discussion of the 

outlook for this pathway.

Text Box 2. Benefits and Challenges of Utility Partnerships

In states with fully regulated electricity markets, like those in the Southeast, corporate customers can 

pursue partnerships with their utility to procure additional renewable energy on the customer’s behalf.

Some utilities in the Southeast have received regulatory approval to procure utility-scale renewable 

energy projects for corporate customers in the form of green tariff programs or bilateral contracts. The 

key benefits and challenges to this approach are summarized in Table 3.

Table 3. Key Benefits and Challenges of Utility Partnerships

Benefits Challenges

• Reduced project development and operation 

requirements

• Flexible contract terms

• Potentially lower electricity costs, if the cost 

of the RE is less than existing rates over the 

contract term

• Opportunity for energy price hedge

• Limited availability in the southeast

• Potentially high renewable product cost

• Contract length and building lease terms may vary, 

which can limit corporate interest

4.1.1 Market Status

Utilities in Alabama, Georgia, North Carolina, and Tennessee have partnered with corporate 

customers to procure renewable energy. These partnerships have resulted in more than 405 MW 

of renewable capacity in the Southeast.

3 Georgia has the most capacity, followed by North 

Carolina, Alabama, and Tennessee (Figure 8). Of the 405 MW, green tariff programs have 

supported the most renewable deployment in the Southeast. 

 

3 At least four other contracts have been announced, but the capacity under those contracts has not been disclosed 

publicly. This includes two TVA contracts with Google, one Walton EMC contract with Facebook, and one Georgia 

Power contract with Switch (Judge 2015; Trubey 2017; Underwood 2018; Walton EMC 2018). 
12

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Figure 8. Contracted renewable energy capacity by state and utility partnership type. 

Sources: Heeter et al. 2017, World Resources Institute 2018

Two utilities in the Southeast have adopted green tariff programs: Duke Energy in North 

Carolina and Georgia Power. Duke Energy has the most experience; these programs received

approval for Duke’s North Carolina Green Source Rider program in 2013 (NCUC 2013). The 

program closed in 2016 and resulted in 111 MW of photovoltaic (PV) procurement on behalf of 

Google and two other anonymous corporate customers (Tawney, Barua, and Bonugli 2018). In 

2017, North Carolina passed HB 589, a bill that required Duke Energy to develop a successor 

program titled “Green Source Advantage.”4 Duke Energy has proposed the program, but it has

not yet been approved by North Carolina regulators. 

Georgia Power’s program was launched in 2017 and the utility announced 177.5 MW of 

contracted PV capacity in 2018.5 Google has procured 78.8 MW of this capacity (Demasi 2018), 

and the remaining capacity is divided between three off-takers (Johnson & Johnson, Target, and 

Walmart) (Georgia Power 2018a). 

After these two programs, Alabama Power’s bilateral contract with Walmart for 56.8 MW of PV 

accounts for the most capacity. Georgia Power’s 50 MW biomass contract with Procter & 

Gamble and Volkswagen’s 10 MW PV project with the Tennessee Valley Authority (TVA)

round out contracted capacity. In summary, Google accounts for about one-third of contracted 

capacity across the Southeast (Figure 9).

 

4 For bill language see: https://www.ncleg.net/Sessions/2017/Bills/House/PDF/H589v6.pdf (accessed August 18, 2018). 5 We include Georgia Power’s green tariff is “contracted” in 2017 in our figures, since that is when the program was 

launched, however, individual off-taker contracts were signed in 2018.

0

50

100

150

200

250

Florida Mississippi Tennessee Alabama North

Carolina

Georgia

Capacity (MW)

Bilateral Agreements Green Tariffs
13

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Figure 9. Annual utility partnership contracted capacity by company in the Southeast. 

Source: Heeter et al. (2017) and World Resources Institute (2018)

Alabama Power, Duke Energy, and Georgia Power’s programs have supported the most 

deployment, and each varies on several key program elements (Table 4). Though these programs 

differ in many respects, we focus on three key elements: Eligible participants, contract length, 

and program capacity limits. 

• Eligibility requirements can limit which types of corporate customers can participate. 

Alabama Power allows any corporate customer to participate. Georgia Power limits 

access to those customers exceeding 3 MW of aggregate peak demand. Duke Energy’s 

program, per statute, carves out capacity for certain customers including the University of 

North Carolina, and the remaining unreserved capacity is available to corporate 

customers that exceed 1 MW of demand or an aggregate of 5 MW across facilities. 

• Each utility also offers different contract lengths. Alabama Power negotiates contract 

lengths on a case-by-case basis, and Duke Energy and Georgia Power offer a range of 

contract durations—from as few as 2 years to as many as 30 years. 

• Each utility has differing program capacity caps and expiration dates. Alabama 

Power’s program will close in 2021 with no more than 500 MW of contracted capacity. 

Georgia Power’s program already has closed. If Duke Energy’s program is approved, it 

would expire after either five years or after 600 MW of capacity has been contracted.

0

20

40

60

80

100

120

140

160

180

200

2011 2012 2013 2014 2015 2016 2017 2018

Capacity (MW)

Google Anonymous Three Offtakers Walmart Procter & Gamble Volkswagen
14

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Table 4. Comparison of Southeastern Utility Partnerships

Alabama

Power

Duke Energy 

(Expired in 

2016)

Duke Energy 

(As proposed 

in 2018)

Georgia

Power

State Alabama North Carolina North Carolina Georgia

Program Renewable 

Generation 

Certificate

Green Source 

Rider

Green Source 

Advantage

C&I Renewable 

Energy 

Development 

Initiative 

Program

Eligible 

Participants

Any interested 

corporate customer

Certain classes 

of large 

customers with 

new load since 

2012

Universities, 

military 

installations, and 

other certain

nonresidential 

customers

Annual Peak 

demand ≥ 3 MW

Potential 

Cost 

Savings

Each project must 

provide benefit to all 

ratepayers, 

potentially including 

financial contribution 

from customer

Credit capped at 

renewable 

energy cost, so 

no cost savings 

potential

Depends on 

long-term 

market rates

Depends on 

long-term market 

rates

Length of 

Contract

Negotiated 5 to 10 years Negotiated 

depending on 

contract 

selected, 

standard offer is

20 years

At least 10 years

REC 

Treatmenta

Negotiated RECs owned by 

customer

RECs owned by 

customer

RECs owned by 

customer

Enrollment 

Period and 

Program 

Limits

Biennial RFP or 

unsolicited bid, 

capped at 500 MW

through 2021, 

individual projects 

are limited to 80 MW

Three-year 

enrollment 

period from 

2013 to 2016, 

capped at 

1,000,000 MWh

Enrollment 

period expected 

to begin in 2019, 

capped at 

600 MW, with 

carve-outs by 

customer type

Interested 

companies must 

have participated 

in Notice of 

Intent Process in 

2017, capped at 

200 MW

Early Exit 

Fees

Negotiated Equal to the net 

present value of 

remaining PPA 

cost

Early 

termination fee 

included

Customer may 

not re-subscribe 

after early 

termination

Contracted 

Capacity

56.8 MW 111 MW Enrollment to 

begin in 2019

177.5 MW

a REC treatment addresses which party owns the RECs from the contracted electricity supply. Renewable 

energy credit ownership is required to make a renewable energy claim; if an entity does not own the 

RECs, it cannot say—in marketing claims, greenhouse gas disclosures, or elsewhere—that it is using 

renewable energy.
15

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4.1.2 Case Study: Georgia Power’s Green Tariff

Georgia Power’s green tariff is the newest in the region and has also supported the most 

contracted capacity. This case study details the history and structure of this program.

The green tariff took more than a year from the time it was ordered to be considered and when it 

was approved. On August 2, 2016, the Georgia Public Service Commission (GPSC) issued an 

order approving Georgia Power’s 2016 Integrated Resource Plan (GPSC 2016).6 In the order, the 

GPSC required Georgia Power to consider the development of a commercial and industrial 

(C&I) renewable energy program. The program was not to exceed 200 MW and required

approval by the GPSC prior to implementation (Georgia Power 2017a). In the months following 

the order, Georgia Power worked with its corporate customers to understand their renewable 

energy objectives and to develop a program in line with the GPSC’s requirements. Georgia 

Power filed the C&I Renewable Energy Development Initiative (REDI) Program for approval 

July 20, 2017. The GPSC approved the program August 9, 2017 (GSPC 2017).

Corporate customers were required to indicate their intention to participate, then the utility

offered pricing for the corporate customer to evaluate prior to signing the contract. Eligible 

corporate customers (those with annual aggregate load exceeding 3 MW) were required to 

participate in a Notice of Intent process. The corporate customer had to pay a $5,000 

participation fee, and identify its proposed subscription level in MW, contract length (from 10 to 

30 years), and any other requirements related to its interest (Georgia Power 2017a).

After expressing interest, companies then were offered a price based on the costliest contract 

accepted in Georgia Power’s REDI procurement for 510 MW of utility-supplied renewables.

Though the exact price offered is confidential, GPSC staff have disclosed that the average cost of 

the REDI projects was approximately $0.036 per kilowatt-hour, and that all procured projects 

were below Georgia Power’s avoided cost (Barber and Kaduk 2018). The two projects selected 

for the C&I REDI program included the 120-MW Dougherty County Solar Facility and the 57.5-

MW Tanglewood Solar Facility. Prospective corporate customers could make a final decision on 

participation prior to signing the renewable contract. The signed contracts then were reviewed 

and approved by the GPSC (Georgia Power 2018b; GPSC 2018).

Google, Johnson & Johnson, Target, and Walmart have subscribed to the available capacity in 

the C&I REDI Program. Google is the only company to disclose its 78.8 MW share and praise

the program suggesting that it “shows that providing a cost-competitive, fixed-price clean power 

option is not only good for the environment, it also makes business sense” (Demasi 2018).

Corporate interest in this program likely was associated with the low cost of the renewable 

product. Interviewees suggested that the low average cost allowed the utility to both justify the 

program under the stipulations of the GSPC and provide corporate customers a cheaper product. 

Interviewees noted that one reason why Georgia Power was able to minimize program costs was 

by bundling the C&I REDI procurement process with the already planned REDI procurement 

 

6 Georgia does not have a renewable portfolio standard. Renewable energy planning is conducted via the integrated 

resource planning process. 
16

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process. This allowed the utility to maximize resources already invested and which are 

associated with bid review and interconnection analysis, among other tasks.

If Georgia Power expands the green tariff from its 200 MW cap, it might benefit from coupling 

the tariff with future supply-driven procurement processes. This expansion would require 

additional GPSC approvals and Georgia Power has suggested that it might consider a new 

program but it has not offered a timeline or additional details (Georgia Power 2018c). 

4.1.3 Outlook

Utility partnerships have resulted in about 471 MW of renewable procurement on behalf of 

corporate customers. This procurement pathway might be of interest to corporate customers, 

given that the structure of energy markets in the Southeast could require utility involvement in 

any corporate utility-scale procurement. 

There is significant capacity still to be developed under existing program structures. Alabama 

Power (426 MW) and Duke Energy (600 MW) have about 1 GW of available capacity within 

their programs. In addition to these utilities, cooperatives in the Southeast also are exploring 

options with corporate customers (NRECA 2018b). This represents a significant opportunity for 

companies located in these utility service territories.

Corporates looking for a program outside of Alabama Power and Duke Energy’s territory will 

need to develop one with their utility. This presents challenges, as not all utilities will be

interested in partnering. Some utilities in the Southeast do not have experience with this type of 

corporate procurement, which could add delay and costs that a corporate customer would have to 

absorb. If utilities are interested in developing a green tariff, they might consider a similar 

program to that of Georgia Power which has supported the most deployment across the 

Southeast.
17

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Text Box 3. Military Partnerships

Some utilities across the Southeast have partnered with the U.S. Department of Defense (DOD) to 

expand renewable energy procurement. These projects differ from green tariffs and bilateral contracts in 

that the DOD site is providing land for a renewable generator but not contracting for the renewable 

energy. These projects allow DOD sites to receive other benefits—such as enhanced grid resiliency—

and provide a location for utilities to site new renewable energy projects. A variation of this pathway 

might be of interest for corporate customers with significant land availability. 

Through 2017, 421 MW of renewable capacity has been deployed at military installations across the 

Southeast all from utility-scale PV.7 Most of this capacity was contracted in 2014 and 2015 and has 

begun to taper off in recent years (see Figure 10). Overall, Georgia (176 MW) has the most capacity, 

followed by Florida (147 MW), and Tennessee (53 MW). 

Figure 10. Contracted renewable capacity at Southeast military installations by state. 

Though the U.S. Army and the U.S. Navy both have six solar projects located on government land, the 

navy’s capacity nearly doubles that of the Army—273 MW of capacity versus 120 MW (see Table 5). 

The U.S. Air Force trails with 30 MW of capacity sited at the Eglin Air Force Base. This capacity is all 

from PV projects, and the U.S. Army Redstone Arsenal and the U.S. Army Sunny Point projects also 

incorporate battery storage.

Table 5. Military Partnerships by State, Project Host, and Year

State

Project 

Host Utility

Project 

Location

Capacity and 

Technology

Estimated 

Contract 

Year

Alabama U.S. 

Army

TVA (Behind-themeter project)Redstone 

Arsenal

10 MW PV and 

1 MW / 2MWh battery 

storage

2016

Alabama U.S. 

Army

Alabama Power Anniston 

Army Depot

7 MW PV 2015

Alabama U.S. 

Army

Alabama Power Fort Rucker 10 MW PV 2015

0

50

100

150

200

250

2014 2015 2016 2017

Capacity (MW)

Tennessee North Carolina Alabama Florida Georgia
18

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Florida U.S. Air 

Force

Gulf Power Eglin Air 

Force Base

30 MW PV 2015

Florida U.S. Navy Gulf Power Pensacola 

Saufley 

Field

65 MW PV 2015

Florida U.S. Navy Gulf Power Whiting 

Field

52 MW PV 2015

Georgia U.S. 

Army

Georgia Power Fort 

Benning

30 MW PV 2014

Georgia U.S. 

Army

Georgia Power Fort Gordon 30 MW PV 2014

Georgia U.S. 

Army

Georgia Power Fort 

Stewart

30 MW PV 2014

Georgia U.S. Navy Georgia Power Albany 44 MW PV 2016

Georgia U.S. Navy Georgia Power Kings Bay 42 MW PV 2015

North Carolina U.S. 

Army

Brunswick EMC Sunny Point 1.2 MW PV and 840 kWh 

battery storage

2016

North Carolina U.S. Navy Duke Energy 

(Progress)

Camp 

Lejeune

17 MW PV 2015

Tennessee U.S. Navy TVA Mid-South 53 MW PV 2016

Sources: Griffin (2015); Ahlen et al. (2018); TVA (2016); U.S. Air Force (2017); and U.S. Army (2018a)

Though these projects are located on military-owned land, in all but one of the cases (Redstone Arsenal), 

the power is transmitted back to the grid.8 Each military base typically does not own the RECs 

associated with that power generation. Rather, the power is used to serve all utility customers and the 

utility retains the RECs. Utilities can keep the RECs and use them to make renewable energy claims, sell 

the RECs to specific customers, or sell the RECs to third parties for the benefit of all ratepayers. In 

exchange for siting these projects on military land, the military receives increased local resiliency in the 

event of a broader grid outage.

Other corporate customers might consider a similar partnership with a utility. These customers could 

pursue a deal where the corporate customer receives a similar reliability option as is done for the military 

customers, or the customer might consider leasing the land in exchange for a portion of the RECs from 

the project. This approach might not be for all corporate customers, given the significant land-holding 

requirements. 

4.2 Community Solar

This section describes community solar benefits and challenges to corporate participation (see

Text Box 4), and overall deployment in the Southeast. Nearly 60% of community solar 

deployment in the Southeast has been completed by cooperative utilities. This section includes a 

 

7 Florida Power & Light also has sited a 10-MW facility at the U.S. National Aeronautics and Space 

Administration’s Kennedy Space Center facility (Beutel and Anderson 2010).

8 The Redstone Arsenal project is behind the meter (U.S. Army 2018b; SunPower 2018). 
19

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profile of the cooperative utility community solar market, and concludes with the market outlook 

for this pathway.

Text Box 4. Benefits and Challenges of Community Solar

Community solar programs allow eligible utility customers to subscribe to the generation of a solar 

project (typically < 1 to 5 MW). Eligible ratepayers, typically businesses and residential customers, can 

enter into a contract with their utility or a third-party developer to subscribe to a share of the solar 

project. The key benefits and challenges of this approach are summarized in Table 6. 

Table 6. Key Benefits and Challenges of Community Solar

Benefits Challenges

• Projects can be located off-site, but close to 

the point of consumption

• Project branding and community 

involvement opportunities may exist

• Projects may provide access to more 

capacity than might be available on-site

• Projects may offer long-term electricity price 

certainty

• Corporate subscription and capacity caps may apply, 

potentially requiring a corporate customer to participate 

in many projects to achieve renewable goals

• REC ownership is not offered in all community solar 

projects, without RECs the subscription cannot be 

applied to renewable goals

• Potentially higher renewable product costs than 

alternatives

4.2.1 Market Status

Through 2017, five of the seven Southeastern states have operating community solar programs

(Cook and Shah 2018). Only one state—North Carolina—mandates the provision of community 

solar for certain utilities; in the other five states utilities are offering programs voluntarily. There 

are 57 community solar projects located in the Southeast with a cumulative capacity of 101 MW.

Georgia has the most community solar capacity, followed by Florida and South Carolina 

(Figure 11) and community solar deployment saw significant growth in 2016 and 2017. 

0

5

10

15

20

25

30

35

40

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Capacity (MW)

FL GA NC SC TN
20

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Figure 11. Community solar capacity installed by year and state.

Source: O’Shaughnessy et al. (2017) and NRECA (2018a)

Note: There are an additional 23 MW of community solar in various cooperative utilities in Georgia; data on when 

these projects were installed was not available. 

It is unclear how many corporates participate in community solar programs, and some programs 

prohibit or limit the share or size of corporate subscriptions. Table 7 summarizes a set of 

community solar programs across the Southeast to illustrate the variation in program design and 

corporate access. Community solar programs developed by electric cooperatives also are 

highlighted in section 4.3.2. We identified three key factors important for corporate participation 

in community solar: access, cost, and REC treatment.

Table 7. Comparison of Selected Community Solar Programs Across the Southeast

Utility (State)

Duke Energy 

(NC)

Georgia 

Power

City of 

Tallahassee (FL) SCE&G

TVA (AL, 

GA, MS, NC, 

and TN)

Year 2019a 2017 2017 2017 2015b

Program Cap 40 MWc 3 MW No specified capd 16 MW 10 MWe

Subscribed 

Capacity

In 

development

Not disclosed 20 MW 16 MW Varies by 

project f

Project Size 

Cap

5 MW ≤ 2 MW No specified cap Minimum size 

of 1 MW; 

maximum of 

10 MW

Minimum size 

of 50 kW; 

maximum 

size of 2 MW

Corporate 

Eligibility

Yes No Yes g Municipalities, 

churches, and 

schools

Can vary by 

project

Maximum 

Subscription

Size

≤ 2 MW ≤ 10 kW Up to 100% of 

demand 

≤ 1 MW Can vary by 

project

Subscriber 

Compensation

Estimated 

$500 fee, with 

bill credit of 

$0.05/kWh for 

20-year 

contract

$24.99/kW per 

month and bill 

credit of 

$0.03/kWh in 

2018, and

escalating 

thereafterh

Subscriber pays 

$0.05/kWh for life 

of 20-year 

contracti

Monthly fee of 

$0.20/kW and 

bill credit of 

$0.01/kWhj

Can vary by 

project

REC 

Treatment

RECs owned 

by customer

RECs owned 

by customer

REC treatment is 

unclear

Utility retains 

ownership of 

RECs

Can vary by 

project

a This is the proposed effective date of Duke’s proposed program that has not yet been approved by the NCUC.

b TVA launched a pilot community solar program in 2014. In 2016 and 2017, TVA offered its Distributed Solar 

Solutions program, for which community solar projects were eligible. These projects must compete against other 
21

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eligible distributed solar projects. The information listed here is in reference to the Distributed Solar Solutions 

program offered in 2017. 

c The 40-MW cap is spread equally across Duke Energy Carolinas and Progress.

d The city has not set a cap, but currently plans to build another 40-MW project that will be available for individual 

subscriptions (Faris 2018).

e Community solar projects must compete with other projects under this 10-MW cap.

f TVA has allocated all 10 MW to 7 projects, but subscribed capacity within each project varies. 

g Small- and medium-sized commercial electric utility customers are eligible, large industrial customers might be 

ineligible.

h For more information on rates see Georgia Power 2017b.

i City of Tallahassee customers currently pay $0.035/kWh (City of Tallahassee 2018).

j Up-front fee is $2.25/watt and bill credit is for first 20 years of contract; for subsequent 15 years, subscriber can 

receive credit for avoided cost of generation at that time.

The structure of North Carolina’s program, including the high program and project cap, might

offer eligible corporate customers the most access to community solar subscriptions. If fully built 

out, Duke (Carolinas and Progress) could construct 40 MW of community solar projects. 

Individual, eligible corporate customers can subscribe to 2 MW of a project, assuming the 

project is the maximum size of 5 MW (see Table 7).9 Corporate eligibility varies considerably 

among programs in other states. In the South Carolina Electric & Gas Company (SCE&G)

program, only certain customer types can participate, such as municipal governments. The City 

of Tallahassee determines corporate eligibility by customer size (small and mid-scale 

commercial customers are eligible). For TVA, corporate eligibility varies based on the 

distribution utility’s program rules, and corporate customers are prohibited from participating in 

Georgia Power’s program.

Access to the program is not sufficient to drive corporate subscriptions in community solar; the 

cost of participation is another key factor (Cook and Shah 2018). Most of the programs surveyed 

apply monthly fees and credit PV generation at the avoided cost of electricity as opposed to the 

retail rate. Compensation at the retail rate coupled with low monthly fees offers more 

subscription value than the avoided cost rate, which might be more attractive to interested 

corporate subscribers. 

Similarly, REC treatment can influence corporate interest. Many corporations want to own the 

RECs associated with their subscriptions to meet their corporate renewable energy goals. In most 

programs in the Southeast, the subscriber owns the RECs. In some cases, the utility retains the 

RECs (e.g., SCE&G) or ownership is unclear (e.g., TVA and City of Tallahassee). In the case of 

TVA and for City of Tallahassee, corporate customers must pursue other options to achieve their 

renewable energy goals. 

 

9 North Carolina’s program was mandated in HB 589, see the bill language here: 

https://www.ncleg.net/Sessions/2017/Bills/House/PDF/H589v6.pdf. The program has not yet been approved by the NCUC. 

For more information on this regulatory proceeding, see Docket E-7, Sub 1168 here: 

http://starw1.ncuc.net/NCUC/page/docket-docs/PSC/DocketDetails.aspx?DocketId=f14c8254-25b7-4feb-a2f5-

24e6f8264b2a. 
22

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4.2.2 Case Study: Corporate Access to Cooperative Utility

Community Solar Programs

Though investor-owned utilities have adopted community solar programs in recent years, 

cooperative utilities accounted for about two-thirds of Southeast community solar capacity 

through 2017. This section tracks the history of this market and examines cooperative utility 

community solar programs and corporate access. 

Nationwide, the National Rural Electric Cooperative Association (NRECA) tracks 132 MW of 

community solar projects across electric cooperatives and nearly half of this capacity (59 MW) is

in the Southeast (NRECA 2018a).

10 The capacity by cooperatives in the Southeast is distributed 

across 57 projects located in 5 states, with Georgia leading at 50 MW (Figure 12). 

Figure 12. Cooperative utility community solar deployment as compared to other utilities in the 

Southeast. Source: O’Shaughnessy et al. (2017) and NRECA (2018a)

Interviewees suggested that the main reason cooperative utilities have launched community solar 

programs is the requests from members for more renewable energy options. For example, Cobb 

Electric Membership Corporation’s 7.7 MW Azalea community solar project is one of the largest 

 

10 The focus here is on subscription-based community solar. Cooperative electricity consumers are member-owners 

of the cooperative, thus any solar project constructed on behalf of all customers could be considered a form of 

shared solar. Excluding subscription-based projects, southeastern cooperatives have deployed 313 MW of 

“cooperative shared solar,” with most of the deployment in Georgia (192 MW) and Mississippi (59 MW). 
23

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cooperative projects across the Southeast and was constructed to diversify the cooperative’s 

energy mix and provide members more direct access to renewable energy (Cobb EMC 2018). 

Not all cooperative customers can participate in community solar projects, particularly corporate 

members. In many cases only residential customers are eligible, and in some cases all 

members—including corporate customers—are eligible to participate. In the Southeast, corporate 

customers are ineligible for 50% of cooperative utility community solar projects, as compared to 

31% that allow any member to participate, and 19% for which eligibility rules are unclear (see

Figure 13). 

Figure 13. Corporate customer eligibility in cooperative utility community solar projects

in the Southeast.

Though certain corporate customers can participate in cooperative utility community solar 

projects, subscriptions can be limited to very small shares. The average project size for this 

subset of community solar projects is 420 kW, and most utilities limit subscriptions to 5 kW or 

less. For about half of these projects the incumbent utility also owns the RECs; in the remaining 

cases the ownership is unclear.

As all utility types—including cooperatives—gain experience with community solar programs, 

interviewees suggested that they could expand their offerings. This could include allowing 

corporate eligibility, increasing subscription sizes, and building larger projects. Southeastern 

utilities also could consider innovative solar partnerships with corporate customers like those

adopted in other regions of the country. Organic Valley, for example, partnered with municipal 

utilities in Iowa, Minnesota, and Wisconsin to support the development of 29 MW of new

community-scale PV projects (Guevara-Stone 2017). Organic Valley agreed to purchase the 

RECs associated with 12 MW of the projects for the 25-year life of the contract. In turn, the 

member utilities purchase the electricity to serve all their members, including Organic Valley

(Organic Valley 2017; Guevara-Stone 2017). Organic Valley’s role in the project—including its 

REC payments—reduced the overall cost of the contract, resulting in lower-cost electricity for all 

ratepayers. Utility interest in this and other innovative approaches varies based on member 

Ineligible

50%

Eligible

31%

Uncertain

19%
24

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

interest and other local considerations—which will shape this segment of the community solar 

market going forward.

4.2.3 Outlook

Community solar programs have expanded in recent years and corporate customers can 

participate in at least some of these programs. North Carolina might represent the largest 

community solar market with 40 MW of mandated community solar, but corporate interest in 

this and other state markets will be contingent upon program structure and other factors, such as 

price and REC treatment.

Corporate customers also will have to weigh this option in relation to other potentially lower-cost 

procurement options, such as utility partnerships. For smaller corporate customers, community 

solar subscription sizes might be sufficient to achieve renewable targets, but this is not the case 

for many mid- and large-size customers. In the Southeast, for example, a few large corporate 

customers have procured about 400 MW of renewable energy via green tariffs, and the entire 

community solar market in the Southeast is about 100 MW. As a result, community solar could

be a component of corporate renewable procurement strategy, but it is unlikely that a large 

corporate customer can achieve its goals through this pathway alone.

4.3 Competitive Market Access

In some states, corporations can participate in competitive markets to procure renewable energy 

by joining retail choice programs or pursuing an off-site PPA. Both options can help 

corporations meet their renewable objectives, but these approaches, especially retail choice,

rarely are available across the Southeast. This section summarizes each distinct approach along 

with the benefits and challenges of the more prevalent off-site PPA (Text Box 5). This discussion 

is followed with an assessment of the off-site PPA market status. It concludes with a case study 

of the Conetoe II Solar project in North Carolina, and an outlook for competitive market access 

in the Southeast.
25

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Text Box 5. Considerations for Retail Choice and Benefits and Challenges of Off-Site 

Renewable PPAs

Retail choice programs allow customers to select their energy supplier—either a competitive supplier 

or the incumbent electric utility. By selecting a competitive energy supplier, customers might be able to 

negotiate the terms of the electricity contract including renewable energy content.

Georgia is the only state in the Southeast where retail choice is available.11 In contrast to some other 

states that offer retail choice to all customer classes (i.e., residential and business customers), Georgia’s 

program is limited to new large corporate customers with loads that equal or exceed 900 kW (GPSC 

n.d.). These new facilities have a one-time opportunity to pursue retail choice. Once the facility selects 

a supplier, it no longer can pursue other service providers. This structure imposes risk on the 

corporation related to electricity rate volatility, which could help explain why no Georgia load was 

served by competitive suppliers in 2016 (EIA 2017). Should these programs become more available in 

the Southeast, corporate customers might wish to review the benefits and challenges associated with 

this pathway as articulated by Heeter et al. (2017). 

Off-site renewable PPAs allow a corporate purchaser to contract with a project developer to procure 

renewable generation. A PPA can be either physical or financial. In a physical PPA, the corporate 

purchaser contracts with a developer to deliver power to a facility. In a financial—or virtual—PPA, the 

company buys rights to the power, but it is not delivered. Rather, the power is resold on the wholesale 

market. Financial PPAs are the most common, given that this structure offers flexibility to the 

corporate purchaser in siting projects.

Given retail choice is limited in the southeast, only the key benefits and challenges of off-site PPAs are 

summarized in Table 8. 

Table 8. Key Benefits and Challenges of Off-site PPAs

Benefits Challenges

• Reduced project development and operation 

requirements

• Potential long-term financial return as 

compared to market rates

• Opportunity for energy price hedge

• Uncertain and volatile electricity rates can influence the 

long-term financial value of the investment

• Higher risk of imperfect energy price hedge, given 

facilities may be sited far from load.

• Typical 20-year, or longer, contract terms may not align 

with building lease terms or facility long-term plans, 

which can limit corporate interest

4.3.1 Market Status

Any corporate customer in the Southeast could pursue a PPA with a project sited in a regional 

transmission organization (RTO) or independent system operator (ISO) footprint. A key benefit 

of PPAs is electricity price hedging, however, and the risk of an imperfect hedge is significant 

when a project is located far from load and in a different market (Heeter et al. 2017). For the 

Southeast, only portions of North Carolina, Mississippi, and Tennessee are served by RTOs. For 

example, Entergy Mississippi participates in the Midcontinent Independent System Operator 

(MISO) market, and Dominion Energy’s territory in North Carolina and American Electric 

Power’s territory in Tennessee participate in PJM Interconnection, Inc. (PJM). These utility 

service territories cover about 25% of C&I load in Mississippi, 4% of load in North Carolina, 

 

11 In comparison, 20 states outside the Southeast offer at least some form of retail choice (Heeter, Cook, and Bird 

2017). 
26

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

and 2% of load in Tennessee.

12 Companies located in these service territories could be best 

positioned to pursue an off-site PPA, provided their rate structure is aligned with wholesale rates. 

Facilities in other states or utility service territories might consider this option, but price hedging 

risks might be significant. 

To date, corporations have procured approximately 171 MW of off-site PPA capacity located in 

the Southeast, all derived from PV projects in North Carolina (Figure 14). In most cases, an 

individual company contracted with a developer for the project. One project, however, is an

aggregate PPA: The Massachusetts Institute of Technology (MIT) project is unique, given the 

university partnered with the Boston Medical Center Corporation and the Post Office Square 

Redevelopment Corporation to aggregate its load for one larger project (Heeter et al. 2017). 

Figure 14. Offsite financial PPAs contracted in North Carolina by year and off-taker. 

Source: Heeter et al. 2017

Although corporations have procured renewable generation in North Carolina, about half of the 

capacity serves out-of-state load, including the MIT project.

13 Half of Lockheed Martin’s project 

also is applied to load in the PJM footprint, although it is unclear what facilities are associated 

with the remaining capacity (Labrador 2016). Corning Inc. also has not specified the facilities it 

associates with its contract, though it does have operations in North Carolina (Corning Inc. 

 

12 These estimates are based on EIA (2017) data for North Carolina, Mississippi, and Tennessee. There are a variety 

of other utilities that participate in RTOs that serve comparatively less C&I load. In both North Carolina and 

Tennessee, the impact on C&I load is negligible. In the case of Mississippi, incorporating these other utility service 

territories increases the percentage of C&I load served by RTOs to 38%. A full listing of these utilities can be found 

in EIA (2017). 

13 The 208-MW Amazon Wind Farm U.S. East project also is located in North Carolina, but it was procured via 

Dominion Energy’s Green tariff program offered in Virginia for load in that state. For more information on this 

project see Bird et al. 2017.

0

20

40

60

80

100

120

2012 2013 2014 2015 2016 2017

Contracted Capacity (MW)

Apple Corning MIT et al. Lockheed Martin
27

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

2015). Lastly, Apple’s contract is used for its data center near Maiden, North Carolina. In 

summary, 50% of PPA capacity located in North Carolina is applied to out-of-state load, 38% is 

unclear, and 12% is applied to in-state facilities.

4.3.2 Case Study: Conetoe II Solar Project

The Conetoe II Solar Project (Conetoe II) has two separate PPAs, one with Lockheed Martin and 

one with Corning Inc. Both companies have load dispersed across the United States, and 

Lockheed Martin applies its financial PPA to multiple locations in different utility-service 

territories. This approach might be of interest to companies seeking to pursue the benefits of a 

PPA for facilities that are in the Southeast. This case study outlines the reasons that these two 

corporations pursued their PPAs and the structure of those deals, with an emphasis on Lockheed 

Martin’s approach. 

Corning Inc. and Lockheed Martin both noted their interest in a renewable PPA on 

environmental and economic grounds. Both Lockheed Martin and Corning Inc. have 

commitments to improve their environmental stewardship and this project helps them achieve 

that objective. These companies also were interested in the long-term energy-price hedge value 

offered by their PPA (Labrador 2016; Corning Inc. 2015).

Though they had these common goals the companies pursued their deals separately, both 

utilizing a renewable energy procurement consultant, CustomerFirst Renewables. In December 

2015, Corning Inc. signed a 25-year fixed-price PPA with Duke Energy Renewables for 50 MW 

of the 80 MW facility. In February 2016, Lockheed Martin signed a 17-year fixed-price contract 

with Duke Energy Renewables for the remaining 30 MW (Labrador 2016). The power is sold 

into the PJM Interconnection market and the corporations then are compensated whenever the 

price received for the PV generation exceeds the fixed PPA price over the life of the contract, 

thereby allowing the project to hedge against long-term electricity rate volatility. Environmental 

attributes were also important to both corporations. Corning receives RECs from the project and 

Lockheed Martin receives replacement RECs (RECs sourced from another renewable energy 

project).

Lockheed Martin’s contract is unique, stemming from the company’s internal approval process 

along with the participation of load outside PJM. Lockheed Martin has a decentralized structure, 

requiring the company to seek approval from its internal business organizations and specific 

locations before making energy-procurement decisions on their behalf (Labrador 2016). This 

could increase the time and resources needed to secure a PPA than would be the case in a more 

top-down structure. Half of Lockheed Martin’s contracted capacity also is associated with 

locations outside PJM (Labrador 2016). This approach increases the complexity of the long-term 

price-hedging analysis, because the company must estimate future prices across multiple 

markets. 

Lockheed Martin retained the ability to internally allocate the project’s generation to different

business units or facilities without impacting the contract. This allows Lockheed Martin to 

maximize its price-hedging opportunity as market rates evolve. Ultimately, other companies 
28

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

located in the Southeast might consider a similar PPA structure to that of Lockheed Martin to 

achieve their own renewable objectives and to manage associated risk.

14

4.3.3 Outlook

The lack of corporate participation in the two competitive market pathways (retail choice and 

off-site PPAs) is a function of the limited access Southeastern companies have to these options. 

Retail choice only is available to some large, new corporate customers in Georgia. In 

comparison, companies have more direct access to wholesale markets in parts of three states—

Mississippi, North Carolina, and Tennessee.

Expanding corporate access to retail choice would require new legislation to introduce 

competition into electricity markets15—or a utility could seek approval to join these markets

voluntarily. Entergy Mississippi joined MISO in 2013 and could serve as a model for other 

Southeastern utilities interested in taking this approach (RTO Insider 2013). Even so, no state or 

utility is actively considering these options, suggesting that the Southeast policy environment is 

likely to remain stable in the near-term. Without policy change, corporate access to these 

pathways will remain limited. In this environment, the approach taken by Lockheed Martin could 

be of interest to other companies with Southeastern load. This approach, however, introduces the 

significant risk associated with locating projects far from load.

4.4 Public Utility Regulatory Policies Act Qualifying Facilities

A few corporate customers in the Southeast have used PURPA to support their renewable 

procurement objectives. This section describes the benefits and challenges of developing PURPA 

qualifying facilities to achieve corporate renewable objectives (see Text Box 6) and overall 

deployment in the Southeast. North Carolina represents the largest PURPA market across the 

region. This section profiles North Carolina’s market before concluding with the outlook for 

following the PURPA pathway. 

 

14 First Third Bank’s virtual PPA for an 80-MW solar project in North Carolina also might be of interest to 

corporations with load in both regulated and wholesale markets (Fifth Third Bank 2018). 

15 Nevada is actively considering reforms to its electricity market, which might be of interest to Southeastern states 

(Associated Press 2016). 
29

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Text Box 6. Benefits and Challenges of PURPA Qualifying Facilities

The Public Utility Regulatory Policy Act of 1978 (PURPA) requires electric utilities to purchase power 

from certain projects termed, “qualifying facilities.”16 There are two general types of qualifying 

facilities: Small power producers and cogeneration facilities. To qualify as a small power producer, a 

project must be 80 MW or less and must generate electricity from renewable energy (such as PV). To 

qualify as a cogeneration facility, the project must generate electricity in tandem with another form of 

energy—typically thermal. The key benefits and challenges of developing a renewable PURPA 

qualifying facility are listed in Table 9.

Table 9. Key Benefits and Challenges of PURPA Qualifying Facilities

Benefits Challenges

• This option is widely available in the 

Southeast

• A corporation can serve as either the project 

developer or contract with a third-party to 

develop and operate the project

• Corporations may lack the relevant expertise to 

develop a renewable project and contracting with a 

third-party can add costs and complexity

• There is limited transparency into how PURPA rates 

are determined, which makes it difficult to understand 

potential benefits of this approach as compared to 

others

• Many PURPA programs in the southeast do not offer 

fixed long-term rates for qualifying facilities, subjecting 

the developer to long-term financial risk

• Developing a PURPA project can require extensive 

negotiations with the utility that a corporation may not 

be willing to pursue absent certainty on associated 

rates

4.4.1 Market Status

Through 2017, there were 4.4 GW of PURPA capacity operating across 624 facilities in the 

Southeast (Figure 16). Only about 60 MW of that capacity, however, is owned by the 

corporations themselves.

Of total PURPA capacity in the Southeast, PV accounts for 70% of this capacity, followed by 

biomass, and landfill gas. The majority of Southeast PURPA capacity is located in North 

Carolina (59%) followed by Florida and Georgia. Of PURPA PV projects, after North Carolina, 

Georgia has the most PV capacity deployed and it is spread over far fewer projects. In North 

Carolina, PV facilities have an average capacity of 5.7 MW; in Georgia the average size is 

23 MW. Outside of these two states, PV deployment has been comparatively low, particularly in 

Alabama and Florida. In addition to this existing capacity, 1.2 GW of PV—virtually all in North 

Carolina—is in various stages of development (Figure 15).17

 

16 For bill language see https://www.gpo.gov/fdsys/pkg/STATUTE-92/pdf/STATUTE-92-Pg3117.pdf (accessed 

August 20, 2018). 17 Figure 16 relies on the final release of 2016 data from Form EIA 860. The PURPA projects in this list that might 

have come online after release of this dataset were cross referenced with data from SNL Financial Inc to confirm 

operating status in 2017. This dataset might not include all the PURPA projects that are planned or have come 

online through 2017. 
30

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Figure 15. Small power-producer qualifying facility capacity by state and technology through 

2016. Source: Energy Information Administration (2018b) and SNL Financial Inc. (2018)

Corporations directly own 7 of the 624 PURPA facilities, which are all located in North 

Carolina. Apple leads all other corporate owners in terms of capacity (46.5 MW), followed by 

Shoe Show and United Therapeutics (Figure 16). Of Apple’s three PURPA facilities, two are

utility-scale PV projects (20 MW and 21 MW) near and adjacent to its Maiden, North Carolina,

data center (Elmer-Dewitt 2012). In comparison, Shoe Show and United Therapeutics have built 

5 MW and 4 MW rooftop systems at their corporate headquarters respectively (Schneider 

Electric 2014; DFR Construction 2009). QVC has constructed a 3.5-MW ground-mounted 

system at its Rocky Mount Distribution Center and Bernhardt Furniture Company has installed a 

1-MW rooftop PV project at one of its production facilities (Russell 2016; QVC Inc. 2013).

Figure 16. Corporate renewable PURPA capacity by technology type in the Southeast.

Source: Energy Information Administration (2018b) and SNL Financial Inc. (2018)

0

500

1000

1500

2000

2500

3000

3500

4000

AL MS TN SC GA FL NC

Capacity (MW)

Other Technology PV Planned PV

0

5

10

15

20

25

30

35

40

45

50

Apple Shoe Show United

Therapeutics

QVC Bernhardt

Furniture

Capacity (MW)

PV Other Technology
31

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Interviewees suggested that the most important considerations for pursuing a PURPA contract 

are the length of the contract and the avoided cost rate. States have discretion to establish the 

method for determining the avoided cost rate paid to qualifying facilities. The approach taken 

can impact the rate, and thus be more or less favorable to qualifying facilities. Some of the more 

common avoided-cost methodologies are defined as follows.

• The proxy method assumes that a qualifying facility delays or displaces the next planned 

generating unit, typically a combined-cycle natural gas plant. The proxy unit’s fixed costs 

establish the capacity payment, and the variable costs set the avoided energy rate. 

• The peaker method is somewhat common across the Southeast. In this methodology, the 

qualifying facility is assumed to displace the most expensive peaking resource on the 

utility’s system, typically a natural gas–combustion turbine. The avoided energy cost rate 

is based on the capacity value offered by the displaced peaking resource and its marginal 

production costs.

• The differential revenue requirement method quantifies the cost of generation for the 

utility with and without a certain amount of qualifying facility capacity with certain 

characteristics. The avoided cost rate is the difference between a scenario with and 

without a specified block of power. 

• The market-based method typically is used in jurisdictions with access to wholesale 

markets. In this arrangement, qualifying facilities participate in day-ahead or hourly 

markets and receive compensation based on market clearing prices.

• The competitive bidding method establishes qualifying facility avoided cost rates based 

on solicitations for capacity. The highest-cost winning bid serves as the avoided cost rate 

for other qualifying facilities that did not win but might wish to sell electricity to the 

utility. 

Table 6 displays key elements of PURPA programs for utility-scale projects at some of the 

largest electric service providers in each state, along with the Tennessee Valley Authority 

(TVA). 

Of the utilities listed in Table 10, Duke Energy Carolinas and South Carolina Electric & Gas 

Company are the only utilities that offer long-term contracts with fixed rates to PURPA projects. 

In both cases, these utilities also provide a capacity value for years when a capacity need is 

identified. Interviewees suggested that this program structure is preferable for utility-scale PV 

projects because it provides long-term price certainty. 

The other utilities, such as Alabama Power and Florida Power & Light (FP&L), instead pay 

PURPA facilities the actual avoided costs incurred when the facility is operating, often under 

short-term contracts. In some cases, these facilities receive the system-wide avoided costs—as is 

the case in Alabama Power’s territory—and FP&L establishes avoided-cost rates for specific 

geographic regions. Regardless, qualifying facilities in these utility territories are subject to 

market-price volatility and the associated challenges of financing projects given that volatility. 

Additionally, Entergy Mississippi is a member of MISO and has received approval to limit its 
32

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

PURPA program to projects ≤ 20 MW.

18 Projects larger than that would participate in MISO 

wholesale markets.

Table 10. Comparison of Select PURPA Rates by Largest Electric Retailer in Each State

Utility 

(State[s])

Rate 

Schedule

Eligible 

Capacity

Contract 

Length

Cost 

Method

Cost 

Schedule

Estimated 

or Fixed 

Rates

Capacity 

Value

Alabama 

Power (AL)

CPE ≤ 80 MW 1 year with 

evergreen 

(automatic) 

renewal

System 

dispatch 

modelling

Fixed rate, 

updated 

annually

Summer 

Peak: 

$0.04/kWh

NonSummer 

Peak:

$0.03/kWh

NonSummer 

off-peak:

$0.02/kWh

Capacity 

payment 

might be 

available 

when 

capacity 

need is 

identified

Duke 

Energy 

Carolinas 

(NC)

Negotiated ≤ 80 MW 5 years Peaker 

method, CT

Fixed rate 

for life of 

contract, 

set every 2 

years

Negotiated Included in 

years that 

capacity 

need is 

identified

Duke 

Energy 

Carolinas 

(NC)

Schedule 

PP

≤ 1 MW 10 years Peaker 

method, CT

Fixed rate 

for life of 

contract, 

set every 2 

years

On-peak: 

$0.04/kWh

Off-peak: 

$0.03/kWh

On-peak 

Summer:

$0.01/kWh

On-peak nonsummer: 

$0.02/kWh

Entergy 

Mississippi 

(MS)

Negotiated ≤ 20 MW Negotiated Negotiated Negotiated Negotiated Negotiated

Florida 

Power & 

Light (FL)

COG-1 ≤ 80 MW Not 

specified

Peaker 

method by 

geographic 

area, gas 

turbine

Real-time 

hourly

Estimate 

offered by 

written 

request

Could

negotiate to 

include when 

capacity 

need occurs

Georgia 

Power (GA)

Negotiated ≤ 80 MW Not 

specified

Peaker 

method, CT

Real-time 

hourly 

Average all 

hours 

(2017–

2027):

$0.04/kWh

Included 

when 

capacity 

need occurs

Mississippi 

Power

Negotiated ≤ 80 MW Negotiated Production 

cost 

modeling

Fixed rates 

set when 

Negotiated Might include 

when 

 

18 The Federal Energy Regulatory Commission has the authority to exempt certain utilities from the provisions of 

PURPA, if the utility can show that a prospective qualifying facility has nondiscriminatory access to a competitive 

market such as MISO and PJM. 
33

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Utility 

(State[s])

Rate 

Schedule

Eligible 

Capacity

Contract 

Length

Cost 

Method

Cost 

Schedule

Estimated 

or Fixed 

Rates

Capacity 

Value

contract 

signed

capacity 

need occurs

South 

Carolina 

Electric & 

Gas 

Company

(SC)

PR-2 100 kW 

≤ X 

≤ 80 MW

Up to 15 

years

Differential 

revenue 

requirement, 

(100 MW of 

capacity)

Fixed rate 

for life of 

contract, 

rates set 

biannually

Average 

monthly 

payment of 

$0.03/kWh

(2018–

2032)

No capacity 

payment is 

available in 

most recent 

rate structure

Tennessee 

Valley 

Authority 

(AL, GA, 

MS, NC, 

and TN)

DPP ≤ 80 MW 5 years Peaker 

method, 

marginal 

unit

Rates set 

monthly

Not 

published

No capacity 

payment

4.4.2 Case Study: The Evolution of North Carolina PURPA Policies

The robust growth in PURPA capacity across the Southeast has spurred policy discussions 

regarding the goal and design of PURPA programs (Warren 2017). States are grappling with the 

intent of PURPA to allow renewable power generators access to markets, and managing risk 

associated with avoided-cost rate imbalances. With 483 qualifying facilities statewide, North 

Carolina has seen the most PURPA deployment across the Southeast. The state recently also has 

adopted policy changes emblematic of policy discussions elsewhere in the Southeast, including 

Georgia and South Carolina. This case study examines North Carolina’s PURPA program to 

understand what historical factors have driven deployment and how policy changes can influence 

this pathway. 

Most of North Carolina’s PUPRA facilities came online between 2012 and 2016, when the state 

saw on average 59% annual growth in qualified facilities (see Figure 17). As noted, PV 

dominates these PURPA projects, capturing 91% of all the PURPA capacity in 2016 as 

compared to 23% of all projects (a total of 13) in 2008.

Figure 17. Total qualifying facilities by year in the state of North Carolina.

Source: Energy Information Administration (2018b) and SNL Financial Inc. (2018)

0

50

100

150

200

250

300

350

400

450

500

2008 2009 2010 2011 2012 2013 2014 2015 2016

Total Qualifying Facilities (MW)
34

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

For large-scale PV projects (those exceeding 1 MW), historically there were two key PURPA 

pathways in North Carolina—the standard offer and negotiated rates. For the standard offer, the 

state required obligated utilities (Duke Energy [Carolinas and Progress] and Dominion) to 

establish fixed-rate contracts for facilities with capacity of 5 MW or less. These fixed rates were 

determined based on the utility’s projected avoided cost over the life of the contract. Developers 

could then select 5- , 10- , or 15-year contracts with locked-in long-term rates. Rates for new 

contracts were established on a biennial basis. Any facility that had a capacity greater than 

5 MW—or that was not interested in the standard offer—had to pursue negotiations with the 

utility to establish fixed long-term rates under a 10-year contract.

The structure of the standard-offer program was attractive to solar developers and might help 

explain why average PURPA facility capacity averages about 5 MW across North Carolina. The 

biennial avoided cost rate structure can offer developers more certainty regarding project value 

during the planning and construction phase, because the price that qualifying facilities (QFs) will 

receive for their long-term contract is known during that entire biennial term. Additionally, these 

fixed rates allow the developer to avoid the risks associated with energy market price volatility 

present in other utility PURPA programs. The 5-MW capacity threshold, which was unique in 

the Southeast, allows the developer to leverage some economies of scale by spreading fixed costs 

over more generation. The 15-year contract structure is favorable, given that financiers are more 

willing to invest in these longer-term projects. The availability of the off-the-shelf rate structure 

alleviated the need to conduct uncertain negotiations with the utility.

In addition to this developer-friendly program, North Carolina also offered a renewable energy 

tax credit that provided a maximum incentive of $2.5 million to offset project equipment and 

installation expenditures (including PV) that were used for a business purpose.19 Before expiring 

at the end of 2015, this tax credit could be paired with the federal investment tax credit to 

significantly reduce the overall cost of PV projects.20 These PV projects then could apply as 

PURPA facilities and receive fixed rates for their generation. In summary, favorable program 

structure and tax incentives could explain why developers pursued 5-MW PV projects in large 

numbers. 

In 2017, the North Carolina legislature enacted House Bill 589, which revised the state’s PURPA 

program to phaseout the existing standard-offer program and alter the negotiated-rate program

for obligated utilities. For the standard-offer program, the law reduced eligibility from 5 MW to 

1 MW and reduced the contract length from 15 years to 10 years. 21 Once an obligated utility’s 

cumulative capacity under this program structure reaches 100 MW, the project eligibility 

threshold is further reduced to 100 kW. The law also made changes to the negotiated-rate 

program. Most importantly, utilities were no longer obligated to sign 10-year contracts with 

qualified facilities, instead utilities can sign 5-year contracts. The project developer then must

renegotiate for subsequent contracts, which could be at lower rates. HB 589 also developed a 

 

19 The allowable tax credit also could not exceed 50% of the taxpayer’s state tax liability for the year. For 

information on the North Carolina tax credit, see “Renewable Energy Tax Credit (Personal),” 

http://programs.dsireusa.org/system/program/detail/541. 20 For more information on the ITC, see “Business Energy Investment Tax Credit (ITC),” 

https://energy.gov/savings/business-energy-investment-tax-credit-itc. 21 For bill language, see https://www.ncleg.net/Sessions/2017/Bills/House/PDF/H589v6.pdf. 
35

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new competitive procurement process for large renewable energy projects. Duke Energy is 

required to procure 2,660 MW of renewable energy over a term of 45 months. The law requires 

Duke to issue a series of request for proposals to procure renewable energy projects to meet this 

goal. At maximum, 30% of the capacity can be sourced from utility-owned projects. Prospective 

qualifying facility developers can submit bids to serve this utility capacity. The lowest cost bids 

would then be selected and serve as the basis for setting the avoided-cost rates for other projects 

that are not selected but wish to negotiate a subsequent PURPA contract. 

Though it is unclear how these programmatic changes will influence PURPA interest, 

interviewees offered some perspectives at this early stage. As noted, there is 1.2 GW of PURPArelated capacity already in the pipeline. Going forward, some interviewees argued that the new 

solicitation structure will increase competition, foster innovation, and reduce utility PURPAcompliance costs. Other participants had a somewhat different perspective. These individuals 

were generally supportive of the mandated renewable procurement but were concerned about the 

lower PURPA rates that projects might receive, the future of the market once Duke meets its 

procurement goal, and the costs associated with preparing a bid in an uncertain market. 

Clarifying the full impacts of these changes will not be possible until the full implementation of 

the competitive solicitations in 2021.

4.4.3 Outlook

Although some companies—such as Apple—own PURPA facilities, this approach is not 

widespread. Recent changes in PURPA programs could further limit interest in this approach. 

North Carolina supports the most PURPA deployment across the Southeast and changes in its 

standard offer contract pricing and length can reduce developer and corporate interest in 

pursuing PURPA projects. 

Aside from North Carolina, South Carolina is the only state that offers fixed rates for long-term 

projects and has the second largest PURPA pipeline. Given changes in North Carolina’s 

program, PURPA-related deployment might be concentrated in South Carolina. For example, a 

corporate PURPA partnership between Solvay S.A. and Dominion Energy brought a 71-MW PV 

project to the state in late 2017 (Andorka 2018; Solvay S.A. 2017).22 Interest in subsequent 

PURPA projects will be impacted by utility-rate structures that have seen downward pressure on 

fixed energy rates and capacity value in the state. Therefore, the overall PURPA market could

decline in future years, limiting the potential for corporations to pursue these options. 

The emergence of competitive renewable project solicitations by utilities also might impact 

corporate interest. This is because developers might submit the least-cost renewable energy 

projects for utility procurement, and corporate customers then would have to pursue potentially 

higher-cost projects that did not win the competitive solicitation. At the same time, utilities 

across the Southeast are beginning to provide corporate customers other options to pursue 

renewables that might prove more attractive to achieve corporate objectives. 

 

22 In this project, Solvay pays for the RECs and Dominion sells the power to SCE&G. When the project was brought 

online, it was the largest PV project in South Carolina (Andorka 2018; Solvay S.A. 2017). 
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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

4.5 Emerging Pathways

This section provides additional models for off-site procurement that could work in the Southeast 

context. The section highlights the model structure, requirements, and benefits to the utility and 

corporate purchaser. 

4.5.1 Model 1. Large-Scale Land Lease for Renewables

In this model (see Figure 18), a corporation with a large amount of land could lease part of the 

land to a project developer (either a utility or a third party). The electricity produced would be 

used by the local utility. In exchange, the corporate could receive land-use payments or the RECs 

from the project. The corporate could also negotiate other requirements, such as having the 

renewable system serve the corporate campus during grid outages. 

Similar models have been used by the U.S. military in the Southeast, though military facilities 

have not negotiated RECs from the systems. This model would work well for corporates with 

large amounts of available land, such as the military, industrial facilities, and state agencies. 

Under this model, the utility would benefit by getting land from a host customer and being able 

to easily site a new renewable project. The utility also would get all the generation produced by 

the renewable generator. The customer would benefit by receiving the services it negotiated—

land-use payments, RECs, grid services, and other services. 

Figure 18. Large-scale land lease for renewables.

4.5.2 Model 2. PURPA-Based Contract-for-Differences Model

Existing PURPA rates and contract terms in most of the Southeast make renewable project 

development challenging. In this model (see Figure 20), a corporate would agree to a fixed price 

for the renewable generation. If the generator received more than this via its PURPA contract, 

then the net would go to the corporate. If the generator received less than the fixed price, then the 

corporate would pay the net difference to the generator. This structure mimics a financial PPA 

with a project selling into the wholesale market, but instead of the project receiving the marketbased wholesale price, the project would receive the PURPA avoided-cost rate (see Figure 19). If 
37

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

the state’s PURPA provisions only provide a short-term contract, then the structure might need 

to be modified. The fixed price could also include payment for the project’s RECs. 

A similar model was used by Organic Valley to support 12 MW of solar projects in the Upper 

Midwest Municipal Energy Group (UMMEG). Organic Valley signed a 25-year REC contract 

and the solar projects are compensated by the local municipal utility for the energy produced and 

for their capacity. All of the electricity produced by the solar projects is used by the utility—

similar to a PURPA contract—but, for this deal, the customer and customer’s agent (One Energy 

Renewables) viewed a utility contract as more favorable than a PURPA contract. The contract 

also was viewed as a faster process than that of negotiating a green tariff, which would have 

required approval by the state’s public utility commission. The utility expects that retail rates 

will decline because of these projects, which provide a benefit to the utility and its ratepayers 

(including Organic Valley). 

Under this model, the utility could save money if the cost of the solar project is less than higherpriced wholesale power contracts. The utility also keeps its relationship with the customer, 

avoiding or mitigating behind-the-meter solar installations. The customer benefits by being able 

to support a new renewable energy project, potentially at lower cost than that of their present 

REC purchases. Depending on the negotiated price, however, the customer might be paying 

more than if they previously were using purely grid-supplied electricity. 

Figure 19. PURPA-based contract for differences.

4.5.3 Model 3. Market-Based Rates and Separate Contract with an Off-Site 

Project in RTO/ISO Territory

There are a few small pockets in the Southeast that are covered by an RTO/ISO. These include 

Dominion’s territory in North Carolina (PJM), American Electric Power’s territory in Tennessee 

(PJM), and Entergy’s territory in Mississippi (MISO). Corporates could sign a financial PPA 

with a generator located in one of these regions, and pair that contract with a market-based rate 

from their utility (see Figure 20). Currently, most electricity rates do not fluctuate with the same 

frequency as wholesale market rates. If a utility adopted a “market-based rate,” which passed on 

the variability of wholesale rates to their customers, then customers would have a better option to 
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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

match a financial PPA (contract-for-differences) with the renewable generator. For example, if

the generator and customer are in PJM and PJM prices go up, then the solar provider will receive 

higher prices for its generation, which can offset the higher prices paid by the customer. 

This model is in place in Dominion Energy Virginia’s territory, with its market-based rate 

(MBR). The MBR is a rate schedule that mimics PJM wholesale-market pricing and fees. 

Amazon Web Services uses this rate and has signed separate contracts for solar energy in 

Virginia (100 MW and 80 MW, both in 2016). As a variation on this, corporates also could sign 

a PPA in the Electric Reliability Council of Texas (ERCOT) territory or some other region and 

apply the RECs from its procurement to load it has in the Southeast. Corporates might be 

hesitant to do so—or to do so at scale—however, because of the associated greater risk.

Under this model, the utility should ensure that it can fully recover its costs. It might need to 

include additional fees to ensure that no other customers are harmed by offering this new rate, 

which would require regulatory approval. This model enables the utility to keep its customers, as 

customers continue to use the utility for 100% of their electricity needs. Customers would benefit 

by being able to better match the rates they pay for electricity with the rates a renewable 

generator would receive.

Figure 20. Market-based rates and separate contract-for-differences with an off-site project in 

RTO/ISO territory.

4.5.4 Model 4. Subscription Solar at Scale, with Corporate Anchor Tenants

To date, much of the community solar market in the Southeast allows for limited participation by 

large corporate entities. Under a new approach, what are now smaller-sized community solar 

projects could be dramatically scaled in size, for example to tens of megawatts (see Figure 21).

23

As utility-scale solar costs decline, this option could be more attractive to utilities than smaller 

community solar projects. Corporate entities could serve as anchor tenants for much of the load, 

 

23 This model would vary from what most consider “community solar” in that it might not be installed on the 

distribution system.
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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

reserving the remaining subscriptions for residential and small commercial customers. This 

option has the potential to drive down subscription costs by reducing the cost of the PV array on 

a per-watt basis, as well as potentially reducing customer acquisition and other costs. To lessen

customer acquisition cost, corporate anchor tenants also could offer subscriptions to their 

employees and could sign a flexible anchor tenant agreement; this would allow their subscription 

to size within a given range (e.g., between 50% and 60% of the project’s output). 

Figure 21. Market-based rates and separate contract with an off-site project in RTO/ISO territory.
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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

5 Summary and Market Outlook

Overall, there are nearly 740 MW of off-site renewable projects in the Southeast with corporate 

involvement.

24 This includes PURPA projects with a corporate owner, utility partnerships (green 

tariffs and bilateral agreements), off-site PPAs, and community solar (Figure 22). Utilities have 

developed an additional 380 MW on military sites. 

Figure 221. Contracted off-site corporate renewable capacity in the Southeast, by procurement 

option.

On a state basis, North Carolina has seen the most deployment (344 MW) using a mix of off-site 

PPAs, green tariffs, and PURPA projects. It is followed closely by Georgia (298 MW), which 

also deployed three pathways: Community solar, bilateral agreements, and a green tariff. 

Alabama, Florida, Mississippi, and Tennessee each have seen less than 60 MW of deployment

(Figure 23).

 

24 This estimate was identified by a review of a variety datasets from the Energy Information Administration, SNL 

Financial Inc., and Bloomberg New Energy Finance among others. The estimate was also vetted through discussions 

with electric service providers and corporates across the Southeast. We include Georgia Power’s green tariff is 

“contracted” in 2017 in our figures, since that is when the program was launched, however, individual off-taker 

contracts were signed in 2018.

 -

 50

 100

 150

 200

 250

 300

 350

 400

 450

Corporate-Owned

PURPA Project

Utility Partnership Off-Site PPAs Community Solar

MW of contracted capacity

Alabama Florida Georgia Mississippi North Carolina South Carolina Tennessee
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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Figure 23. Contracted off-site corporate renewable capacity in the Southeast, by state.

The current capacity satisfies 22% of identified renewable energy demand, using the lower

estimate which only includes renewable energy demand from municipal facilities, and not from 

communities as a whole. This renewable energy demand is an underestimate because the study 

was limited to data supplied directly from corporations via Second Nature and Sierra Club’s 

Ready for 100 campaign.

In states with the greatest renewable energy demands (North Carolina, Georgia, and Florida), 

existing pathways could provide 36%, 43%, and 3%, respectively (Figure 24). These pathways 

leave about 4 million MWh of unmet demand. If solar was used to provide that capacity, it 

would result in more than 2,000 MW of new solar projects (assuming a 22% capacity factor). If 

instead of using the lower estimate for renewable energy demand, we use the higher estimate—

which includes community-wide electricity use in cities and counties that have made a renewable 

energy commitment—then unmet demand rises to 26.8 million MWh. If new solar projects were 

to supply that demand, nearly 13,900 MW of new generation would be required. 

0

50

100

150

200

250

300

350

400

Alabama Florida Georgia Mississippi North

Carolina

South

Carolina

Tennessee

Contracted Capacity (MW)

Corporate-Owned PURPA Project Utility Partnership Off-Site PPAs Community Solar
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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Figure 24. Renewable energy demand and contracted renewable energy capacity in the Southeast.

If the planned future capacity in the Southeast is developed, then it would more than double 

current contracted capacity. Planned capacity includes 426 MW remaining in eligibility for 

Alabama Power’s program, 600 MW under Duke Energy’s Green Source Advantage Program, 

and 20 MW of community solar announced by the City of Tallahassee, Florida (Figure 25). 

Figure 25. Contracted and planned future capacity by year and state.

Our estimate of renewable energy demand only includes the corporations who provided data 

directly to NREL. There are likely additional corporations who did not submit data, resulting in 

an underestimate of renewable energy demand. Future analysis could include more robust 

estimates of renewable energy demand, including more detailed estimates of renewable energy 

73%

3%

43%

0%

36%

7% 9%

0%

10%

20%

30%

40%

50%

60%

70%

80%

 -

 500,000

 1,000,000

 1,500,000

 2,000,000

 2,500,000

AL FL GA MS NC SC TN

MWh

RE Demand Existing RE Pathways Percent met by existing options

 -

 200

 400

 600

 800

 1,000

 1,200

2012 2013 2014 2015 2016 2017 Planned

Future

MW of contracted or planned capacity

AL FL GA NC SC TN MS
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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

demand by utility service territory. A more robust estimate of renewable energy demand could 

inform individual utilities seeking to develop programs and policies to support corporate 

procurement of off-site RE. 
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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

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