November 1, 2000

The analyses and conclusions are those of the study team and do not necessarily reflect the views of

other staff members of the Federal Energy Regulatory Commission, any individual Commissioner, or the

Commission itself.
i

Contents

Page

1. Introduction ............................................................ 3-1

2. Supply and Demand Conditions ............................................ 3-3

A. Background ....................................................... 3-3

1. Physical Transmission System .................................. 3-4

2. Generation Capacity .......................................... 3-6

3. Demand .................................................... 3-9

B. Summer 2000 ..................................................... 3-9

1. Temperatures .............................................. 3-10

2. The Weather Effect on the Transmission System ................ 3-12

3. Prices in Summer 2000 ..................................... 3-19

3. Market Structure in the Southeast Region .................................. 3-21

A. Principal Geographic Markets and Products .......................... 3-21

B. Market-Based versus Cost-Based Sales .............................. 3-21

C. Forwards and Futures Contracts .................................... 3-22

D. Divestiture and Merger Activities .................................. 3-25

4. Regulatory and Institutional Environment ................................... 3-25

A. Federal Responsibilities, Statutes, and Provisions ..................... 3-25

1. Tennessee Valley Authority .................................. 3-26

2. The Southeastern Power Administration ........................ 3-28

3. Federal Environmental Regulation of Electric Utilities ........... 3-28

B. RTOs .......................................................... 3-29

C. State Responsibilities, Statutes and Provisions ........................ 3-30

5. Discussion of Inefficiencies in the Southeast ............................... 3-34

A. Transmission Access ............................................. 3-35

B. ATC Issues ...................................................... 3-37

C. TLR Issues ..................................................... 3-38

D. Lack of Information ............................................. 3-39

E. TVA Issues ...................................................... 3-40

F. Florida Law .................................................... 3-41

G. Standards of Conduct ............................................. 3-42

6. Conclusion ............................................................ 3-42
ii

Tables

3-1. Subregions in the Southeast .............................................. 3-3

3-2. Size of the Regions in the Southeast ....................................... 3-4

3-3. Ownership Classification ................................................ 3-4

3-4. Existing and Planned Transmission Capacity, by Subregion .................... 3-6

3-5. Installed Generating Capacity, by Fuel Type ................................. 3-6

3-6. Existing Capacity, by Type of Ownership, 2000 .............................. 3-7

3-7. Existing Capacity, by Subregion, 1998, 1999, 2000 .......................... 3-7

3-8. Planned Generation Capacity, by Subregion, 2001-2002 ...................... 3-8

3-9. Actual Peak Load ....................................................... 3-9

3-10. Flowgates Where TLR Level 3s and Above were Called, May-August 2000 ... 3-16

Figures

3-1. Southeast Transmission System ........................................... 3-5

3-2. Historical Temperature Departure from Norm for the Southeast ............. 3-10

3-3. Average Temperature Departure from Norm for Midwest and Southeast Cities . 3-12

3-4. Daily Maximum Temperature for Atlanta and Chicago, May-August, 2000 ..... 3-13

3-5. Summer TLR Events, Level 3 and Above ................................. 3-14

3-6. SERC TLR Level 3 and Above, Summer 2000 ............................. 3-15

3-7. Daily Spot Price for Natural Gas at Henry Hub ............................ 3-17

3-8. Daily Price Indices: Southern Market Hubs, 1998-2000 .................... 3-20

3-9. Into Entergy Onpeak Forwards, July-August Contracts ...................... 3-23

3-10. Entergy Futures, July Contract ......................................... 3-24

Appendix

SERC Regular Members ................................................ 3-43
3-1

1. Introduction 

The traditional vertically integrated utility model has largely persisted in the

southeastern United States. Relatively low energy costs in the region have discouraged the

state restructuring initiatives seen elsewhere in the country and almost none of the utilities

in the Southeast have divested themselves of generation resources. This continued control

of assets in the Southeast has vastly reduced the economic incentives to utilities to facilitate

activities by independent power producers (IPPs) that the Commission contemplated in

Order No. 888. In many cases, utilities have damped IPP involvement without violating

specific Commission regulations because, as a general matter, the Commission's

regulations provide a lot of flexibility to allow for varying operating circumstances across

the country. 

IPPs face significant difficulties in obtaining access to transmission facilities in the

Southeast. During our investigation, IPPs have told staff, among other things, that utilities'

delays in performing needed studies have jeopardized the viability of proposed merchant

plant projects, that utilities are able to hoard transmission capacity in the name of serving

native load growth in their respective service territories, and utilities are able to manipulate

ATC to their advantage. 

Increased numbers of curtailments, or Transmission Loading Reliefs (TLRs), were

declared in the Southeast in the summer of 2000. IPPs asserted that the ascending number

of TLRs have damaged spot markets, which are most useful for short-term trading. In

addition, they pointed out that because transmission customers often must pay for

transmission that is curtailed, utilities have a reduced incentive to construct transmission

improvements and to take other steps, such as redispatch, to avoid TLRs. Utilities have

shown little inclination to improve transmission access or reduce the incidence of TLRs

largely because the financial impetus for such reforms has been lacking. 

A lack of market information has also helped to stymie the development of markets

in the Southeast. There is no clearinghouse for electric power prices in the Southeast. 

Traders continue to learn prices by using telephones. In addition, price transparency is

reduced because the markets have a limited number of hubs for forwards and futures

contracts. Further, IPPs have reported that ATC postings seem to change constantly, which

contributes to uncertainty in the execution of transmission transactions. 

The Tennessee Valley Authority (TVA), despite having taken steps to participate in

reformed markets, has acted as a bulwark against the development of competitive energy

markets in the Southeast. This is significant because of TVA's substantial presence in the

Southeast. It has 30,000 megawatts (MW) of generation, 29,000 MW of peak load, 2,500

miles of transmission facilities and is critically situated between southern and midwest

markets. TVA has acted differently than other utilities in part because of federal laws that
3-2

restrict its activities. One significant constraint is that sellers other than TVA cannot sell

power at wholesale to distributors in TVA's service territory. Aside from constraints such

as this one, IPPs have reported that TVA has discouraged the siting of new generation in its

service territory by a variety of means, including rejecting requests to perform

interconnection studies, taking excessive time to perform studies and charging excessive

fees to complete studies. 

A final situation significantly impedes the development of competitive energy

markets in peninsular Florida. According to a recent decision of the Florida Supreme Court,

the Florida PSC may not authorize a merchant without retail customers in Florida to

construct a combined cycle plant in excess of 75 MW in the state. This ruling frustrates the

development in Florida of a competitive market for the sale of electric power.
1SERC has experienced two major changes in membership in recent years. On

October 16, 1996, members of FRCC dropped out of SERC forming their own reliability

council. In 1997, Entergy and four other systems dropped their memberships in SPP and

joined SERC. We have reported data pertaining to Entergy in SERC.

3-3

2. Supply and Demand Conditions 

A. Background

The Southeast region consists of Southeastern Electric Reliability Council (SERC)

and Florida Regional Coordinating Council (FRCC). SERC covers 464,000 square miles in

parts of 13 states; it is the largest NERC region, both in load and peak demand. It includes

20 investor-owned utilities, eight cooperatives, seven municipals, four federal/state

systems, four independent producers and 30 power marketers, and is divided into four

subregions: Entergy, Southern, Tennessee Valley Authority (TVA) and Virginia Carolinas

(VACAR).1 FRCC covers peninsular Florida, a total of 62,000 square miles. It includes

four investor-owned utilities. Despite a combined load of 190,000 MW in 1999, SERC and

FRCC constitute only 5.2 percent of the wholesale power trades nationwide. Table 3-1 sets

forth the geographic areas of the four subregions of SERC and for FRCC region. 

Table 3-1. Subregions in the Southeast

Region States Comprised Peaking Season

Entergy Most of Louisiana, Arkansas, Missouri, northeastern

Oklahoma, Southwestern Mississippi, Southeastern Texas,

and three counties of Iowa

Summer 

Southern Alabama, Georgia, Florida, Mississippi and Louisiana Summer 

TVA Most of Tennessee, northern Alabama, northeastern

Mississippi, southwestern Kentucky, and small portions of

Georgia, North Carolina, and Virginia

Summer 

VACAR Virginia, North Carolina and South Carolina Summer 

FRCC Florida Winter 

 Source: NERC ES&D 2000 database.

Table 3-2 presents additional data regarding SERC and FRCC. The respective number

of control areas (CAs) and security coordinators (SCs) in each of these regions suggests

their relative size.

Table 3-2. Size of the Regions in the Southeast
2NERC ES&D 2000 database and SERC's Reliability Review Subcommittee (RRS)

2000 Report. 

3-4

Region No. of Members Square Miles CAs SCs

SERC 73 464,000 17 5

FRCC 33 62,000 12 1

Total 106 526,000 29 6

 Source: SERC Reliability Review Subcommittee 2000 Report and FRCC home page.

Table 3-3 sets forth the number and type of major market participants in SERC and FRCC. 

Table 3-3. Ownership Classification

Owner Classification SERC FRCC Total

IOUs 20 4 24

Cooperatives 8 1 9

Municipals 7 15 22

Federal/State 4 2 6

IPPs 4 1 5

Power Marketers 30 10 40

Total 73 33 106

 Source: SERC Reliability Review Subcommittee (RRS) 2000 Report and FRCC home page. The

Appendix lists the members of SERC and FRCC.

1. Physical Transmission System

The transmission resources in both NERC regions in the Southeast are substantial. 

Figure 3-1 is a map that depicts major transmission lines in the Southeast. In SERC, there

are 20,558 miles of 230 kV transmission lines, 753 miles of 345 kV transmission lines, and

9,230 miles of 500 kV transmission lines. In FRCC, there are 5,267 miles of transmission

lines. The utilities in these regions plan to add approximately seven percent or another

2,500 miles of transmission lines to these totals in the period ending in 2009.2 These data

are captured in Table 3-4. 
3-5

ALABAMA

ARKANSAS

CONNECTICUT

DISTRICT OF COLUMBIA

FLORIDA

GEORGIA

IOWA

ILLINOIS INDIANA

KANSAS

KENTUCKY

LOUISIANA

MASSACHUSETTS

MISSOURI

MISSISSIPPI

NORTH CAROLINA

OHIO NEW JERSEY

OKLAHOMA

PENNSYLVANIA

SOUTH CAROLINA

TAMAULIPAS

TENNESSEE

VIRGINIA

Voltage Category

230kV - 344kV

345kV - 499kV

500kV - 734kV

735kV - 999kV

AC-DC-AC Tie

DC

Figure 3-1. Southeast Transmission System

Source: RDI Powermap, August 2000
3-6

Table 3-4. Existing and Planned Transmission Capacity, by Subregion

Subregion Existing Planned (2000-2009)

230kV 345kV 500kV Total 230kV 345kV 500kV Total

Entergy 2,336 751 2,110 5,197 280 - 64 344

Southern 8,322 - 2,724 11,046 1,129 - 86 1,215

TVA 97 2 2,405 2,504 33 - - -

VACAR 9,803 - 1,991 11,794 387 - 118 505

Total SERC 20,558 753 9,230 30,541 1,829 - 268 2,097

FRCC NA - NA 5,267 NA - NA 416

Total Southeast 35,808 2,513

 Source: NERC ES&D 2000 database.

2. Generation Capacity 

Installed generating capacity in the Southeast region totaled approximately

214,000 MW on January 1, 2000. Of this amount, approximately 39,000 MW or 18

percent is jointly owned by several utilities. Of the installed generation capacity in the

Southeast, 41 percent is coal, 21 percent is gas and 18 percent is nuclear. Table 3-5 sets

forth these data in greater detail. This table indicates the region's relatively heavy

reliance on coal-fired and nuclear generation. 

Table 3-5. Installed Generating Capacity, by Fuel Type

 (Percent)

Subregion Coal Gas Hydro Nuclear Oil Other

Entergy 25 58 0 16 1 0 

Southern 62 10 11 14 3 0 

TVA 49 4 21 22 3 1 

VACAR 45 9 13 25 7 1

 FRCC 25 24 0 10 33 8

Total 41 21 9 18 9 2

 Source: NERC ES&D 2000.
3-7

Ownership of Generating Resources by Investor-Owned Utilities

Investor-owned utilities continue to own the majority of generating capacity in

the region. Table 3-6 sets forth the existing capacity in the Southeast for IOUs, IPPs and

public power entities. In the Southern subregion, Southern owns 70 percent of the

generation. In the Entergy subregion, Entergy owns 71 percent of the generation. In the

entire Southeast region, IOUs own 61 percent, public power entities (including TVA)

own 29 percent and IPPs own 10 percent.

Table 3-6. Existing Capacity, by Type of Ownership, 2000

 (Megawatts)

Subregion IOU Non-IOU Public Power Other Total 

Entergy 22,869 4,049 4,992 177 32,087

Southern 33,926 4,639 10,247 110 48,922

TVA - 3,226 29,359 - 32,585

VACAR 46,726 5,643 7,967 78 60,414

FRCC 27,071 3,968 8,772 249 40,060

Total Southeast

region

130,592 21,525 61,337 614 214,068

 Source: Powerdat, August 2000.

Table 3-7 sets forth existing capacity by subregion in the southeast for the years

1998 through 2000. The table shows that a significant amount of capacity has been

added since 1998, with the exception of FRCC. 

Table 3-7. Existing Capacity, by Subregion, 1998, 1999, 2000

Subregion 1998 1999 %

change

over 1998

2000 %

change

over 1999

Entergy 30,161 30,875 2.4% 31,867 3.2%

Southern 44,933 45,566 1.4% 48,702 6.9%

TVA 29,966 31,402 4.8% 32,585 3.8%

VACAR 57,324 57,539 0.4% 60,258 4.7%

FRCC 38,646 38,929 0.7% 39,562 1.6%

Total Southeast

region

201,030 204,311 1.6% 212,974 4.2%
3SERC RRS 2000 Report.

4Current reporting requirements do not adequately capture merchant plant activity in

the region. Developers are only required to complete FERC Form 867, which is specific to

existing plants or facilities that have a very high probability of coming on line. 

3-8

 Source: August 2000 RDI database compiled from FERC Form 1, EIA-412, RUS7, RUS12.

Planned Generation Capacity Increases

Table 3-8 summarizes planned generation capacity by subregion for the period

2001 to 2002. In sum, total planned generation in the Southeast in 2001 is 15,000 MW

and for 2002 the amount is 26,000 MW. This new capacity is needed to meet

anticipated load growth. Without this planned generation, the regional committed

capacity reserve margin would drop below 10 percent in 2002. SERC's August 2000

RRS report forecasts that the capacity reserve margin will equal or exceed 10 percent in

the years 2001 and 2002. According to FRCC's August 2000 Reliability Assessment,

FRCC's planning reserve margin is 15 percent in 2001 and 2002. 

The need for new generating capacity suggests that a viable market exists to site

merchant plants. In fact, merchants plan to build a significant portion of this new

capacity. In 2000, according to a SERC survey, merchants plan to build 5,340 MW in

generating capacity. This figures decreases to 4,360 MW in 2001 and 3,800 MW in

2002.3 This survey data suggests that merchants have ambitious plans to increase their

presence in the Southeast.4 Whether merchants will realize these plans is unknown at

this time. 

Table 3-8. Planned Generation Capacity, by Subregion, 2001-2002

 (Megawatts)

Subregion Utility Non-Utility Total

Entergy 423 13,461 13,884

Southern 4,187 3,977 8,164

TVA 2,340 2,620 4,960

VACAR 4,100 491 4,591

FRCC 5,566 3,749 9,315

Total Southeast Region 16,616 24,298 40,914

 Source: August 2000 RDI database compiled from FERC Form 1, EIA-412, RUS7, RUS12.
3-9

3. Demand

The actual peak demand for 2000 in the Southeast is 192,000 MW, a slight

increase over the region's 1999 summer peak of nearly 187,000 MW. In 1998, the

peak demand was 182,000 MW. Annual electric energy usage in 1999 of 957,000

GWH was 2.2 percent greater than the 936,000 GWh of energy usage in 1998. These

recent growth figures are consistent with SERC's 2000-2008 forecast of 2.4 percent

for average annual growth in summer peak demand. The rise in annual peak demand

provides further evidence that new generation must be sited in the near-term to keep

pace with demand growth. 

Table 3-9 contains actual peak load figures for 1998 through 2000. In 2000,

Entergy witnessed the largest increase in its load while FRCC saw the lowest. The load

growth for the entire Southeast was 2.8 percent in 1999 and 2000.

Table 3-9. Actual Peak Load

Subregion 1998 1999 % change

over 1998

2000 % change

over 1999

Entergy 26,162 26,558 1.5% 27,987 5.4%

Southern 39,855 42,196 5.9% 43,736 3.6%

TVA 27,343 28,397 3.8% 29,442 3.7%

VACAR 50,057 52,534 4.9% 53,476 1.8%

FRCC 38,730 37,493 -3.2% 37,728* 0.6%

Total Southeast

region

182,147 187,178 2.8% 192,369 2.8%

 Source: SERC home page, NERC Summer 2000 Assessments and ES&D Database.

 * FRCC 2000 demand is projected.

B. Summer 2000

Peak prices were moderate in the Southeast in the summer of 2000. The highest

price reached was $165 per MWh. In contrast, peak prices exceeded $2,000 per MWh

in 1998 and 1999. Moderate peak prices in 2000 occurred, even though temperatures

in the Southeast were slightly above normal this summer, in part because relatively mild

summer temperatures in the Midwest permitted power to be transmitted into the
5The cities selected to represent the various subregions in the Southeast are

Memphis (TVA), Richmond (VACAR), New Orleans (Entergy), Atlanta (Southern), and

Miami (FRCC).

3-10

Southeast from the Midwest at reasonable prices. The transmission of power into the

Southeast during the summer contributed to a significant increase in TLRs.

1. Temperatures

Temperatures averaged approximately 1.4 degrees above normal for the

Southeast as a whole from May through August 2000. Temperatures were 3.2 degrees

above normal in May, in particular, straining local generation resources and causing

power to be transmitted into the Southeast from outside the region. In June, July and

August, Southeast temperatures averaged 0.9, 0.5 and 1.1 degrees above normal. 

Figure 3-2 depicts temperatures relative to average temperatures in five selected

cities in the Southeast for May, June, July and August in each of the past three 

summers.5 As Figure 3-2 shows, a majority of the selected cities experienced

temperatures somewhat below average in the months on May and June in 1999, while,

with few exceptions, temperatures across the Southeast exceeded the average in May

and June 2000. The months of July and August in 2000 saw greater regional variation in

temperatures, with Richmond, Virginia, experiencing cooler than normal weather and

Memphis spiking to more than five degrees above normal. 
3-11

-4

-3

-2

-1

0

1

2

3

4

5

6

Source: NOAA 

New Orleans, LA Atlanta, GA Richmond, VA Miami, FL Memphis, TN

1998 1999

Summer Months May through August

2000

Figure 3-2. Historical Temperature Departure from Norm for the 

 Southeast
6The Midwest is defined as the NERC regions of ECAR, MAIN, MAPP and SPP. 

3-12

Source: NOAA

-4.00

-2.00

0.00

2.00

4.00

6.00

Summer 2000

Degree Fahrenheit

MidWest 3.50 -0.30 -1.40 2.10

TVA 3.99 1.12 1.31 2.65

Entergy/Southern 4.29 0.91 2.76 2.78

VACAR 2.28 0.74 -2.49 -1.64

FRCC 2.49 0.81 0.55 0.73

May Jun Jul Aug

Figure 3-3. Average Temperature Departure from Norm for Midwest 

 and Southeast Cities

2. The Weather Effect on the Transmission System 

Figure 3-3 depicts temperatures relative to the norm in four subregions in the

Southeast and in the Midwest for the four summer months of 2000.6 As the figure

indicates, after being 3.3 degrees above normal in May, temperatures in the Midwest

fell to slightly below normal levels in June and July, before rising again in August to 2.1

degrees above normal. VACAR, the subregion in the Southeast that covers Virginia and

North and South Carolina, experienced lower temperatures than the other subregions in

the Southeast for each of the summer months, dropping to 2.5 degrees below normal in

July and 1.6 degrees below normal in August. The Entergy and Southern subregions

witnessed temperatures at the other extreme; they averaged 2.7 degrees above normal

for the four summer months. TVA and to a lesser extent, FRCC, experienced above

normal temperatures throughout the summer. 

As can be see from Figure 3-3, average temperatures in the Midwest were higher

than normal in May and August 2000. Generation was nonetheless available in the

Midwest during these months to supply markets in the Southeast because the regions

did not experience peak temperatures on the same days. In fact, temperatures were
3-13

40

50

60

70

80

90

100

110

Degrees Fahrenheit

May June July Aug

Atlanta

Chicago

Figure 3-4. Daily Maximum Temperature for Atlanta and Chicago,

 May-August, 2000

considerably lower throughout the Midwest on many days when the Southeast was

experiencing hotter than normal weather. Figure 3-4 illustrates that for two selected

cities, one in each region, maximum daily temperatures varied by 20 degrees or more

on many days this summer.
7Trade press articles also reported this phenomenon. E.g., Megawatt Daily, July

21, 2000, at 7. 

3-14

0

4

0 0 0

1

0

4

8

16

26

13

0

5

10

15

20

25

30

Number of TLRs

1998 1999 2000

Months of May, June, July & August

May June July August

Figure 3-5. Summer TLR Events, Level 3 and Above

In SERC, four TLR Level 3s and higher were called during the summer of 1998

and five such TLRs were called in the summer of 1999. TLR Level 3s and higher

jumped to 63 in the summer of 2000 in SERC. No TLRs were called in FRCC in 1998,

1999 and 2000. Figure 3-5 depicts the TLR Level 3 and higher activity in SERC during

these summers. 

TLR Level 3 and above activity was concentrated this summer in TVA, with

security coordinators in TVA's service territory calling 44, or 70 percent, of all such

TLRs in the Southeast. Figure 3-6 (TLR Map) sets forth the flowgates, direction of

flow and distribution of these TLRs for the period May through August.

Table 3-10 shows the paths on which TLR Level 3s or higher were implemented

this summer. The table indicates that 63 such TLRs were called. The table also

indicates that power flowed into the Southeast.7 
3-15

SERC TLR Level 3 and above for Summer 2000

4

8

3

2

1

1 2

2 3

2 8

2 9

SERC

FRCC

Flowgate Direction of Flow

Cumberland-Davidson & Cumberland-Johnsonville500 KV

Attala-Albertville 161& Bowen Sequoyah

Volunteer-Phipps Bend 500 KV

Bowen-Sequoyah 500KV Webre-Richardson

Sheridan-El Dorado, Hot Spring-McNeil & Marblevale-Sherida-White Bluff New Madrid-Dell

Shawnee-Kelso

Figure 3-6. SERC TLR Level 3 and Above, Summer 2000
3-16

Table 3-10. Flowgates Where TLR Level 3s and Above were Called, May-August 2000

 Flowgate Number of TLRs called

(MW curtailed) Total

ID Name Direction SC CA May Jun Jul Aug TLR Curtailed

SERC

1501 Bowen-Sequoyah 500 NW-SE TVA TVA 0 2 8 1 11 *

1613 Volunteer-Phipps Bend

500

NE-SW TVA TVA 0 8 13 5 26 738 MW

1620 Cumberland-Davidson/

Cumberland-Johnsonville

NW-SE TVA TVA 0 1 3 0 4 *

9139 TVA-EES S TVA TVA 0 1 0 0 1 *

1353 Webre-Richard E-W EES EES 5 0 0 7 12 840 MW

10139 Hot Springs-McNeil 500 S EES EES 0 3 0 0 3 521 MW

1351 New Madrid-Dell S EES AECI 2 0 0 0 2 *

1342 Sheridan-El dorado S EES EES 1 0 0 0 1 

*

1326 Marblevale-SheridanWhite BluffS EES EES 0 1 0 0 1 *

1507 Attala-Albertville 161/

Bowen-Sequoyah

S-SE SOC/

TVA

SOC/

TVA

0 0 2 0 2 

*

Total all Southeast Regions 8 16 26 13 63 2,099 MW

*No curtailment amount listed.
8The summer peak in TVA was almost 3,000 MW above the projected peak of

26,467 MW. As a result the reserve margin was as low as 3 percent at peak demand.

9Six other Level 4 TLRs were called in the Southeast this summer. On those dates,

TVA also imported large quantities of power.

3-17

As discussed above, hotter-than-normal weather in the Southeast was combined

with average or below average temperatures in the Midwest this summer. This caused

increased transfers of power into the Southeast relative to the summer of 1999. 

Transfers of power into SERC exceeding 10,000 MW occurred on days when

temperature differentials were 20 degrees or more. Staff has been informed the TVA's

planning studies indicated that transfers into SERC exceeding 6,000 MW would create

transmission constraints on TVA's system. 

To illustrate our point that the weather pattern triggered imports into the

Southeast that burdened the transmission system, on August 17, 2000, TVA and

Southern experienced their 2000 summer peak. TVA's peak load was 29,344 MW.8 Its

generation at peak was 26,599 MW with net import of 2,478 MW.9 Southern's peak

load was 40,436 MW, generation at peak was 37,155 with net import of 3,281 MW. 

The large import of power triggered a Level 4 TLR called by the TVA security

coordinator.

In addition to the weather pattern, higher natural gas prices contributed to

transmission congestion. As Figure 3-7 indicates, the peak price for natural gas at the

Henry Hub was $2.99/MMBtu in the summer of 1999, and it rose to $4.79/MMBtu in

the summer of 2000. Fewer gas-fired peaking units were used on days of high demand

this summer in the Southeast because the higher cost of natural gas made it cheaper to

purchase electricity generated from coal-fired units in the Midwest. In particular, the

rise in natural gas prices strongly affected Entergy due to its high reliance on gas-fired

generation units.
3-18

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

1/1/1999 4/1/1999 7/1/1999 10/1/1999 1/1/2000 4/1/2000 7/1/2000 10/1/2000

Dollars per MMBtu

Source: Gas Daily. Data through September 29, 2000.

1999 summer peak price = 

$2.99/MMBtu

2000 summer peak price = 

$4.79/MMBtu

Figure 3-7. Daily Spot Price for Natural Gas at Henry Hub
10See also, Power Markets Week, July 24, 2000, p. 13; Megawatt Daily, August

25, 2000, p. 7; Power Markets Week, September 4, 2000, p. 1. 

3-19

3. Prices in Summer 2000 

Peak prices were radically lower in the summer of 2000 than they were in the past

two summers. Figure 3-8 shows that the peak price in the region in 1998 was $2,386 per

MWh. In 1999 it was $2,057 per MWh, but it was only $165 per MWh in 2000. This

figure depicts daily prices at four hubs in the Southeast from 1998 through August 2000. 

The lower peak experienced this summer was due mainly to relatively lower

temperatures for much of the summer in the Midwest. Lower temperatures in the

VACAR subregion relative to other regions in the Southeast increased the availability of

generation to serve customers elsewhere in the Southeast. In addition, utilities appear to

have been better prepared for peak events in the summer of 2000. According to utility

interviews with the Commission staff, superior preparation took the form of increased

hedging through the use of forward contracts, increased generation capacity on line and a

reduced number of forced outages.10
3-20

$ 0

$50

$100

$150

$200

$250

$300

$350

$400

$450

$500

1-Jan-98 1-Jul-98 1-Jan-99 1-Jul-99 1-Jan-00 1-Jul-00

$/MWh

SERC w/o Fla Into TVA Fla-Ga Border Into Entergy

1998 High = 

$2386/MWh

1999 High = 

$2057/MWh

2000 High = 

$164.61/MWh

Source: PowerMarket Week

Figure 3-8. Daily Price Indices: Southern Market Hubs, 1998-2000
11Dominion Resources, Duke Energy, Florida Power, Southern Company, and

Tampa Electric.

12Estimate based on Form-1 data for 1999. 

3-21

3. Market Structure in the Southeast Region

A. Principal Geographic Markets and Products

The Southeast may be divided into five subregional markets: Entergy, Southern,

TVA, VACAR and FRCC. Two periodicals, Megawatt Daily and Power Marketers Week,

report five trading hubs that essentially match these subregions: Into Entergy, Southern,

Into TVA, Florida-Georgia border and Florida In-state. These periodicals reported trades

for a standard 16-hour daily product at all the five hubs. 

Responses to staff's data requests indicate that the investor-owned utilities (IOUs)

offer the transmission and ancillary service required by the Order No. 888, such as pointto-point and network transmission services. However, the types of wholesale trading

activities and the respective products being traded at the hubs varies considerably. 

The IOU's and power marketers learn about prevailing market prices at the market

hubs by consulting with brokers, customers and other market participants, reviewing trade

publications, such as Megawatt Daily, Electric Power Daily, Power Marketers Week. 

The IOU's and power marketers indicate that monitoring web sites and using electric

brokerage services such as Enron OnLine, Altrade, Bloomberg Power Line are useful. 

However, for both IOU's and power marketers the primary means for gathering price

information is through telephone contacts to the various market participants. This is

typical in a purely bilateral market. 

B. Market-Based versus Cost-Based Sales

Wholesale sales comprise a smaller portion of total electric power sales in the

Southeast than in other regions of the country. On the basis of data responses received

from five utilities, wholesale sales comprise 13 percent of their total sales.11 Wholesale

sales in other regions in the country comprise between 20 and 30 percent of total sales in

those sections.12 In addition, of the total wholesale sales reported by the five utilities, 83

percent occurred under cost-based rate authority. This means that only 2.2 percent of the

total sales of the reporting utilities were at wholesale at market-based rates. These facts

suggest that utilities have not used market-based rates extensively to increase sales. 

C. Forwards and Futures Contracts
3-22

Staff reviewed data for forwards contracts that are traded in two hubs in the

Southeast, Into Entergy and Into TVA, and examined futures contracts that are only traded

at the Entergy hub. For the forwards contracts, there has been a general upward trend in

the prices. For example, in July 1997 forwards contracts traded at the $26 per MWh to

$32 per MWh range compared with July 2000 which ranged from $100 per MWh to

$193 MWh at the Entergy hub. The forwards contracts prices appear to be good

indicators of spot market prices. For example, the forwards contracts for July 2000

traded in the $100 per MWh to $193 per MWh range, as compared with the peak spot

market price of $165 per MWh on July 18th at the Entergy hub. Figure 3-9 shows onpeak

July-August forwards contract prices for each year from 1997 through 2000 at the Into

Entergy hub. The figure graphically depicts the rise in prices observed above. 
3-23

$ 0

$50

$100

$150

$200

$250

1-Jul-96 1-Jan-97 1-Jul-97 1-Jan-98 1-Jul-98 1-Jan-99 1-Jul-99 1-Jan-00 1-Jul-00 1-Jan-01 1-Jul-01

$/MWh

LOWDEAL HIGHDEAL

Jul-Aug 97

Contract

Range: $26-32

Jul-Aug 98

Contract

Range: $33-245

Jul-Aug 99

Contract

Range: $83-137

Jul-Aug 00

Contract

Range: $100-193

Jul-Aug 01

Contract

Range: $112-131

Source: Power Markets Week

Figure 3-9. Into Entergy Onpeak Forwards, July-August Contracts
3-24

0

5 0

100

150

200

250

300

7/1/1998 1/1/1999 7/1/1999 1/1/2000 7/1/2000 1/1/2001 7/1/2001

# of Contracts Traded

$ 0

$50

$100

$150

$200

$250

$300

$/MWh

Volume Traded Day High Price $/MWh Day Low Price $/MWh Day Close Price $/MWh

July 1999

Contract

July 2000

Contract

July 2001

Contract

Figure 3-10. Entergy Futures, July Contract

For the futures contracts, there is a less consistent pattern of price growth during

the summer months. However, futures prices rose substantially in the summer of 2000,

which suggests that market participants took a greater interest in futures contracts

activity. Figure 3-10 shows July futures contract prices for each year from 1998 through

2000. The figure indicates that the futures contract price peaked at $235 per MWh in

June 2000. 
13While Nisource, Inc. has assets in the ECAR region, Columbia has operations in

VACAR, which is in the Southeast. 

3-25

D. Divestiture and Merger Activities 

Investor-owned utilities have engaged in significant divestitures of generation assets

in many areas of the country. However, the only divestiture in the Southeast in recent years

occurred when Orlando Utilities Commission sold a 639 MW Indian River Power Plant to

Reliant Energy on September 30, 1999. 

The Southeast has witnessed five mergers in as many years: (1) Duke Power

Company and PanEnergy Corporation; (2) Duke Energy Corporation and Nantahala Power

and Light Company; (3) Dominion Resources, Inc. and Consolidate Natural Gas Company;

(4) Florida Progress Corporation and CP&L Energy, Inc. and (5) NiSource Inc. and

Columbia Energy Group.13 The Commission has conditionally approved these mergers. 

One other merger between Entergy Power Marketing Corporation and Koch Energy Trading

is pending before the Commission. Recently, Entergy Corporation and Florida Power and

Light have announced their intention to merge. 

Most of the mergers noted above were convergence mergers involving electric and

natural gas resources. Non-divestiture of generation resources and rapid merger activity

may tend to increase the domination of IOUs in the Southeast. 

4. Regulatory and Institutional Environment

A. Federal Responsibilities, Statutes, and Provisions

The first part of this section focuses on federal responsibilities and laws that are

unique to, or uniquely impact, the Southeast Region. Chief among these are those federal

laws that govern the Tennessee Valley Authority and the Southeastern Power

Administration. This section then discusses federal environmental regulations and the

status of RTO development in the Southeast. 
14Most of the information for this section comes from “Tennessee Valley Authority

Case Study” by Mary Sharpe Hayes, as appearing in Regulating Regional Power Systems,

edited by Clinton J. Andrews, IEEE Press, 1995.

1516 U.S.C. § 831-831ee (1994 and Supp. III 1997). 

16Order No. 2000, III FERC Stats. & Regs. ¶ 31,089 at 31,200 (1999). 

3-26

1. Tennessee Valley Authority

The Tennessee Valley Authority (TVA) 14 was created by, and operates pursuant to,

the Tennessee Valley Authority Act of 1933, as amended.15 TVA's service area includes

Tennessee and parts of Alabama, Georgia, Kentucky, Mississippi, North Carolina, and

Virginia. TVA's Board of Directors is composed of three persons appointed for 9-year

staggered terms, with one term expiring at each 3-year interval. TVA's rates are set

exclusively by TVA's Board and are not subject to state public service commission or

Commission oversight; nor is TVA responsible to shareholders. However, TVA maintains

ties with electrical distributors, state and local governments, and direct customers. TVA

was initially charged with the planning for the proper use, conservation, and development of

the natural resources of the Tennessee River drainage basin and its adjoining territory. 

As part of the 1959 self-financing amendment to the TVA Act, a “fence” was placed

around TVA, so that TVA and its distributors cannot directly or indirectly be a source of

power supply outside the area supplied with TVA power.16 In addition, TVA is only

permitted to enter into exchange power arrangements with the 14 generating organizations

having such arrangements with TVA on that date. Further, a provision of the Energy Policy

Act prevents other wholesalers from selling inside the TVA area to distributors. Thus, any

energy sold within the fence must be sold to TVA for the beneficial use of all customers.

With regard to its financing, TVA may borrow up to $30 billion to finance the construction

of power facilities, but principal and interest on such loans are payable solely from TVA's

net power proceeds. TVA must make payments to the United States Treasury to repay $1

billion of the appropriations that were invested in the TVA power systems, plus an annual

return on the outstanding investment. Separate federal appropriations are made to support

TVA's non-power activities. 

Because TVA is a federal agency, all significant decisions must be made using the

National Environmental Policy Act (NEPA) guidelines. TVA is also subject to the 1990

Clean Air Act Amendments. 

The Tennessee Valley Public Power Association (TVPPA) is a major market

participant in the Tennessee Valley. TVPPA is a non-profit regional service organization

representing the interests of the 109 municipal utilities and 50 electric cooperatives in the

TVA service area. All but one TVPPA member utility buy wholesale electric power from

TVA and distribute it to eight and one half million customers in seven southeastern states.
1716 U.S.C.A. §§ 824j-824k (West 1985 and Supp. 1994) The Commission

exercised this jurisdiction in AES Power, Inc., 69 FERC ¶ 61,345 (1994), final order, 74

FERC ¶ 61,220 (1996), order on reh'g, 76 FERC ¶ 61,165 (1996). 

18TVA's April 12, 2000, motion to intervene in Entergy Services, Inc., Docket No.

ER00-1933-000, at 2.

19Electric Utility Week, October 16, 2000, p. 16.

20See Title VI, Substitute A to H.R. 2944 (July 12, 2000). 

3-27

The Commission has the authority under section 211 of the Federal Power Act to

require TVA to provide transmission service, if requested to do so by an electric utility.17

In addition, TVA has stated that while it is not required to file an open access transmission

tariff with the Commission, under its Transmission Service Guidelines, which TVA views as

modeled after the Commission's pro forma tariff, TVA provides comparable transmission

service across its system for others.18 TVA also recently has introduced a “5 Percent Plan”

under which distributors in its service area may purchase up to 5 percent of their power

from outside sources, if the price of that power is less than a “point of indifference” price

projected by TVA. Customers must purchase a “5 x 16” product (i.e., purchase power for 5

days, 16 hours a day) and specify unalterable points of receipt and delivery. So far, small

volumes (e.g., 250 MW for 1 week) have been purchased under the program. With regard

to RTO formation, TVA has been working on a RTG proposal involving public power

entities in the Tennessee Valley and adjoining areas.19 

Federal legislation has been introduced that would give the Commission the same

jurisdiction over TVA's transmission of electric power in interstate commerce as the

Commission has over other utilities under the Federal Power Act.20 The proposed

legislation would also remove the fence around TVA limiting the movement of power in

and out of TVA, provide for recovery of stranded costs, and allow TVA distributors

individually to terminate their existing contracts to purchase wholesale electric energy

from TVA three years after giving TVA notice of their intent to do so. This consensus

legislation, which is supported by TVA, TVPPA, and other major players in the Tennessee

Valley market, was included in the Barton electric restructuring bill.
21See SEPA home page at http://sepa.fed.us.

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2. The Southeastern Power Administration

The Southeastern Power Administration (SEPA),21 headquartered in Elberton,

Georgia, has the responsibility to market electric power and energy generated at reservoirs

operated by the U.S. Army Corps of Engineers. SEPA was created in 1950 by the Secretary

of the Interior to carry out the functions assigned to him by the Flood Control Act of 1944. 

In 1977, SEPA was transferred to the Department of Energy. SEPA is organized into four

systems: the Cumberland System located primarily in Tennessee and Kentucky, but also

serving parts of Illinois, Mississippi, Alabama, and Georgia (9 dams); the Kerr-Philpott

System serving Virginia, West Virginia, and a large part of North Carolina (2 dams); the

GA-AL-SC System serving South Carolina, most of Alabama and Georgia, and parts of

North Carolina, Mississippi, and Florida (11 dams); and the Woodruff System serving part

of Florida (1 dam). SEPA markets power to customers (primarily electric cooperatives and

public entities, referred to as preference customers) in all of these states. SEPA does not

own transmission lines and must contract with other utilities to obtain transmission

service.

SEPA's responsibilities include the negotiation, preparation, execution, and

administration of contracts for sale of electric power; the preparation of wholesale rates

and repayment studies; the provision, by construction, contract or otherwise, of

transmission and related facilities to interconnect reservoir projects and to contractual

loads; and activities pertaining to the operation of power facilities to ensure and maintain

continuity of electric service to its customers. 

3. Federal Environmental Regulation of Electric Utilities

The Commission is the primary agency involved in the environmental review of

licensing and construction of jurisdictional hydroelectric facilities. In the Southeast, a

significant amount of the hydroelectric resources are from federally run projects that are

not subject to the Commission's jurisdiction. These are subject to federal environmental

laws, and their power output can be significantly affected by their need to comply with

environmental requirements. Economic and safety review of proposed nuclear power

plants (including site safety matters and disposition of hazardous waste) is vested in the

Nuclear Regulatory Commission and DOE, respectively, with most other environmental

and land use issues reserved to the states or local jurisdictions. Utility operations are also

governed by minimum federal standards for clean air under Title V of the Clean Air Act. 

Regional air quality plans are developed under EPA supervision and administered by the

states. Most important among the standards are ozone, sulfur, particulate, and nitrogen

dioxide (NOx), and carbon dioxide emissions. 

 
22CPL-FPC merger application, Ex. CF-445 at 1-2.

3-29

There are 11 ozone non-attainment areas in the Southeast: Jacksonville/Duval

County, Miami and Tampa in Florida; Charlotte/Gastonia, Greensboro/Winston-Salem/High

Point, and Raleigh/Durham in North Carolina; Knox County, Memphis/Shelby County, and

Nashville in Tennessee; Cherokee County in South Carolina; and Hampton Roads in

Virginia.22

Currently, EPA's ozone transport rule affects most of the fossil fuel plants in the

Southeast. Only the states of Arkansas, Florida, and Mississippi, and those portions of

Texas in SERC, are exempted from this ruling. The rule requires compliance with a

statewide NOx budget during the ozone season of May through September. This budget is

based on 85 percent reduction in electric utility emissions and other reduction levels for

other sources. Currently, compliance with this rule is required by the ozone season of

2003. 

The reductions in emissions are based on fossil units with generating capacity of 25

MW or greater, emitting at a level of 0.15 lbs/MMBtu for NOx. There are provisions in

the rules for an allowance system and use of allowances for compliance. This could allow

some over compliance at some units and use of the excess allowances at others. In general,

most units in the SERC region would likely have to install Selective Catalytic Reduction

(SCR) systems to make the required reductions if they do not burn Western Powder River

Basin coal or gas. SCR systems are estimated to require outages from 8 to 12 weeks for

installation. With a compliance date of 2003 and the engineering and equipment

procurement times required, the majority of these unit retrofits in the SERC region would

have to occur in 2001 and 2002. 

There are provisions in EPA's rule that would allow an extension for compliance to

2005 based on reliability issues but they are rather limited. Some states in SERC have

already issued their draft plans and other states are drafting plans to comply with the rules. 

The entry of new generation that is more efficient than older generation will make it easier

for entities operating in SERC to meet EPA's requirements.

B. RTOs

Aside from the TVRTG described above, there are three RTOs that would be located

wholly within the Southeast: GridSouth, the SeTrans Grid Company and the GridFlorida, all

of which made RTO filings on October 16, 2000. In addition, two RTOs located primarily

in the Midwest would contain utilities located in the Southeast: the Alliance RTO contains

Virginia Power, and the Southwest Power Pool RTO is proposed to include Entergy.

GridSouth
23Unless otherwise noted, the information in this section is from DOE/EIA website,

August 9, 2000, Status of State Electric Industry Restructuring Activity as of August 2000.

3-30

GridSouth is proposed to be a for-profit TRANSCO (transmission company) that

would serve most of North and South Carolina. The transmission owners in GridSouth

would include Duke, Carolina Power & Light, and South Carolina Electric and Gas, but

would exclude the large transmission owning municipal in South Carolina, Santee-Cooper,

whose potential inclusion is complicated by restrictions on its ability to turn over operation

of its assets to a for-profit entity. 

The SeTrans Grid Company

The Southern Companies have proposed the SeTrans Grid Company, which would be

a for-profit TRANSCO that would operate but not own the Southern Companies'

transmission facilities in Alabama, Georgia, and Mississippi, and Northern Florida. It

would have a system wide transmission tariff and would be the sole provider of wholesale

transmission service. The RTO would be the single site administrator for an OASIS for

scheduling transmission and calculating TTC and ATC, and would be responsible for

planning and expansion of the system, and for coordinating with neighboring RTOs

concerning “seams” issues. 

The GridFlorida 

The Florida RTO is proposed to be a for-profit TRANSCO that would cover

peninsular Florida, which is isolated electrically from the rest of the Eastern Interconnect

because of the transmission constraint in northern Florida. All four public utilities will

participate in the RTO. Non-jurisdictional utilities may participate in the Florida RTO but

none of them have indicated to date whether they will do so. 

C. State Responsibilities, Statutes and Provisions

State Restructuring and Retail Access

The states of the Southeast generally have been slower than states in other sections

of the country to require restructuring of the electric industry at the state level.23 The

following section describes the status of state restructuring in the Southeast. As explained

in more detail below, Arkansas and Virginia have required substantial restructuring,

Alabama and Mississippi have decided not to require restructuring for the time being, and

other states continue to study restructuring issues. 
24See Alabama Public Service Commission home page at http://www.psc.state.al.us.

3-31

In Arkansas, restructuring legislation has been enacted that allows for the recovery

of stranded costs, establishes rate freezes, allows for forced divestiture, requires functional

unbundling, and sets retail competition to begin by January 1, 2002. Similarly, in Virginia,

the Virginia Electric Utility Restructuring Act requires: deregulation of generation by

January 1, 2002; the phase-in of consumer choice between January 1, 2002 and January 1,

2004, including pilot programs; rates capped through July 2007 for those who remain with

their incumbent utility; the recovery of stranded costs through capped rates for customers

staying with incumbent utility and through a wires charge for those who switch to

competitive suppliers; and consumer protections such as universal service, education

programs, fuel and emission disclosure requirements, and the allowance of aggregation for

small consumers. 

However, the Alabama Public Service Commission voted on October 2, 2000, to

temporarily suspend the generic investigation of restructuring it had opened in April 1998

until there are wholesale markets in the region.24 The PSC concurred with its staff

recommendation that the burden of proof had not been met that retail competition in

electricity service and restructuring the industry was in the public interest. Accordingly,

Alabama Power Company is to continue as a monopoly provider of retail electric service

until there is a viable wholesale market. Similarly, in Mississippi, the Public Service

Commission concluded that a competitive electric power industry would not be beneficial

to the state's consumers at this time, and suspended the 1996 docket opened to investigate

electric power restructuring. Prices in Mississippi are below the national average, and

studies conducted by the PSC indicate that prices for the residential and small consumers

could rise in a competitive environment. 

Other states continue to study these issues. The Florida Governor has appointed a

commission to study restructuring in Florida. The commission is to report to the Governor

by December 1, 2001, on their investigation of current and future electric reliability,

energy conservation, environmental impacts, supply and delivery options, electric industry

competition, and the financial consequences of restructuring. In January 1998, the Georgia

Public Service Commission issued a staff report on electric industry restructuring. 

Recommendations included market-based rates, unbundled services, and stranded cost

recovery. A docket was established for comments from stakeholders. A slow approach to

restructuring was recommended. 

In March 1999, the Louisiana Public Service Commission issued an order stating

that deliberate and cautious approach was warranted for restructuring the electric utility

industry. A schedule was established through August 2000 to study issues concerning

consumer education, stranded costs, regional planning and reliability, market power, rate

unbundling, functional unbundling, independent system operators, and transition

mechanisms. In Tennessee, as of January 1999, the Tennessee Regulatory Authority

released a report on the deregulation of the industry which identifies 10 issues: rates and
25Tampa Electric Co. et al., v. Joe Garcia, et al., Nos. SC95444, et al., April 20,

2000, 25 Fla. L. Weekly S 730 (Fla. 2000), revised opinion issued September 28, 2000. 

3-32

prices; stranded costs; reliability; market power; universal service; environmental concerns;

taxes; local rate setting; consumer education; and regulatory and legal issues. 

Recommendations for restructuring including any proposed legislation must be made by

February 28, 2001.

In North Carolina, the Study Commission on the Future of Electric Service in North

Carolina has issued its final report with recommendations to open retail electricity markets

to half of the consumers by January 2005, and the other half by January 2006. The study

also recommends a rate freeze until January 2005 to allow utilities to pay down stranded

costs and implementation of a public benefit fund for low-income, renewable energy, and

energy efficiency programs. Issues concerning the stranded costs of municipals were not

addressed. The Study Commission has also announced its intention to hold a series of

meetings and public hearings on deregulation in cities around the state. Issues concerning

the stranded costs of municipals must be resolved before legislation can be drafted for the

2000 legislative session.

In South Carolina, as of March 2000, restructuring legislation (SB 1168) was

introduced and referred to the Committee on Judiciary. The bill would allow retail direct

access within three years. Debate and discussions continue in the House and Senate, but

few expect passage of the bill this session. Also, a report by the Senate Task Force is due

to be released soon.

State Siting Matters

In Florida, independent power producers may not construct combined cycle plants

with a capacity greater than 75 MW. The Florida Supreme Court recently reached this

conclusion in a case in which the state's major utilities challenged the Florida PSC's

authority to permit Duke Power Company and the City of New Smyrna Beach to build a

large combined cycle plant.25 Hence, Florida law severely limits the ability of independent

power producers to site merchant plants. 

Florida appears to be an exception with respect to siting in the Southeast region. 

Market participants have reported favorable experience with siting in the state of

Mississippi. They report that for several years, Mississippi has been actively "recruiting"

new merchant plants by providing information on the state's infrastructure and resources. 

In Mississippi, approximately 6400 MW of new generation is in some phase of

construction or has been installed, and several thousand MW of additional new generation

is planned or recently announced. To date, no permit requests have been denied by the

Mississippi Public Service Commission. Arkansas is also reported to have an expeditious

siting process. 
26CPL-FPC merger application, Ex CF-445 at 5-8.

3-33

In North Carolina, a certificate of public convenience and necessity (PCN

Certificate) granted by the North Carolina Utilities Commission (NCUC) is required for

the construction of a generating facility for the provision of public utility service. Such

certificates are granted, only if the applicant's estimated construction costs are approved

and such construction is consistent with the NCUC's plan for the long-range expansion of

electric generating capacity. This requirement applies to all projects involving the

construction of electric generating capacity, except for generation that would be used to

serve the load of the generation owner. The NCUC has issued an order requesting

comments as to whether it should initiate a generic proceeding to determine how it should

handle future applications to build generating plants in the state that will serve non-native

load. 

In South Carolina, a PCN Certificate issued by the South Carolina Public Service

Commission (SCPSC) is required for the construction of a major utility facility by any

person. A "major utility facility" is defined as an electric generating plant with a capacity

greater than 75 MW or a transmission line with an operating voltage of 125 kV or higher.

The SCPSC is required to make a finding and determination as to, among other things, the

basis of the need for the facility, the nature of the probable environmental impact, whether

the environmental impact is justified, and that the facilities will serve the interest of system

economy and reliability.26
27Market participants provided responses to data and document requests with

requests for confidential treatment pursuant to section 388.112 of the Commission's

regulations, 18 C.F.R. § 388.112 (2000). Accordingly, this report discusses information

provided in these responses in general or aggregate terms. Staff is evaluating whether

action is appropriate to address specific allegations contained in the data responses. 

3-34

5. Discussion of Inefficiencies in the Southeast 

Like the Midwest, the Southeast is dominated by vertically integrated utilities that

maintain substantial generation resources to serve their respective native loads. These

utilities have weak economic incentives to provide transmission access to non-affiliated 

merchants on the same basis as they do to their affiliated merchants. As part of its

investigation of bulk power markets in the Southeast, the Commission's staff met with

representatives of various market participants, including IOUs, IPPs, public power entities

and electric power traders to explore transmission access and related issues. Market

participants also provided responses to staff's data and documents requests.27 

In general, market participants identified several inefficiencies that are frustrating

the development of the bulk power markets in the Southeast. Chief among these are

uncertain transmission access, the inconsistent and apparently aberrant posting of ATC and

concerns that ATC is sometimes withheld, and the lack of transparency regarding

implementation of TLRs. A central theme pervading these concerns is that there is a lack

of current, reliable information available to the market. In addition, the role of TVA as a

major transmission provider that, due to its status as a federal entity not subject to the full

panoply of Commission regulation, has not fully embraced the reforms set forth in the

Commission's Order No. 888, and the restrictive siting law in Florida contribute to

pressures that undermine competitive wholesale energy markets in the Southeast. As noted

in Section 2 above, the significant amount of IOU-owned generation within vertically

integrated transmission systems is larger than anywhere else in the country. This situation

adds to pressures on the wholesale market and may be a matter of concern.

Staff has not verified the accuracy of all the complaints it has received regarding

transmission access, ATC postings and TLRs. The lack of precise, readily available

information, the real time nature of transactions, the resources required to investigate

individual complaints and the operational discretion accorded IOUs retards the staff's

ability to discern the truth in the substantial number of complaints that were brought to it. 

Nonetheless, market participants appear to have less confidence in the Southeast market, in

terms of the ability to conduct wholesale transactions without discrimination, than market

participants have in other regions of the country. This lower degree of confidence appears

to be justified based on investigations that the staff has undertaken and its evaluation of

other complaints. Market participants' reduced confidence weighs heavily on the

maturation of markets into competitive zones of enterprise because it discourages the

investment and participation needed to spur this development. The widespread perception
28Pursuant to the pro forma tariff, the utility should work diligently to complete

studies in less than 60 days. However, the Commission has explained that a utility "may

take more time as long as it explains to the applicant the reason that it needs additional

time." American Electric Power Service Corporation, 91 FERC ¶ 61,308, at 62,049

(2000). The Commission has acknowledged that a study regarding the interconnection of

new generation may often take more than 60 days, PJM Interconnection, L.L.C., 87 FERC ¶

61, 299, at 62,198 (1999), but in such a case, the utility must nonetheless provide a

justification for the extended period required to complete the study. 

3-35

that non-IOU entities do not receive treatment equal to that of IOU-affiliated entities

frustrates the Commission's open access goals. 

 The reforms presaged in the Commission's Order No. 2000—the encouragement of

RTOs—may successfully address many of the discrimination issues that arise from the

present market structure. The Commission may need to be more prescriptive in terms of

how transmission is allocated, depending on whether traditional load allocations persist. 

Some market participants have expressed concerns that existing owners of transmission

capacity would continue to dominate transmission system operations under RTOs. The

formation of RTOs, then, could provide the Commission with an opportunity to take a

structural approach to reduce discrimination but the timing for the creation and operation

of RTOs is uncertain. 

Specific inefficiencies in the Southeast are discussed below. 

A. Transmission Access

Staff's investigation of interconnection issues revealed that procedures governing

utilities' performance of interconnection studies are often unclear. Adherence to

schedules that are established early in the interconnection request process would reduce

the increasingly adversarial climate in which interconnection requests are evaluated. The

time periods chosen to evaluate requests should reflect a reasoned approach to the

technical challenges posed by the request and respect for the IPP's often pressing need for

promptness and certainty. 

In one case, typical of other complaints staff received, an IPP reported that a utility

quoted a period of 11 months to complete the first of several anticipated system impact

studies. In the absence of an explanation that cites the technical reasons why such a period

is required, 11 months to perform a system impact study appears excessive. Studies that

are not promptly commenced and linger over many months cease to be commercially

reasonable.28 Utilities that claim to have insufficient human resources to execute

interconnection studies should adjust staffing levels, or out-source assignments, where

their experience demonstrates that existing staffing and procedures result in significant

delays. 
29E.g., Carolina Power & Light Company, 93 FERC ¶ 61,032 (2000). 

30Entergy Services, Inc., 91 FERC ¶ 61,149 at 61,561 (2000). 

31SkyGen Energy LLC v. Southern Company Services, Inc., 92 FERC ¶ 61,120

(2000). 

3-36

Charges assessed for interconnection studies must reflect costs that the utility

performing the study actually incurs.29 Information from market participants that standard

charges of $10,000 for studies of varying complexity and of charges, as in the case of one

charge in the amount of $50,000, that are reduced when, upon inquiry, the utility cannot

support it, indicate that utilities' approach to charges for interconnection studies is too

often arbitrary. The failure to adhere to the Commission's requirements and to

commercially reasonable standards for administering studies discourages the participation

in the wholesale market that the Commission has sought to encourage. 

The Commission has expressed its sympathy for the difficulties IPPs face when they

seek to site a generation plant amid the uncertainty of transmission access.30 The staff

investigation found evidence that the right of vertically integrated utilities to reserve

transmission capacity has been used to deter merchants from siting plants in their

respective service territories. Utilities have reserved transmission capacity in the name of

serving load growth many years out, effectively deterring IPPs from siting plants in

affected areas. In this connection, several IPPs complained that a utility reserved

transmission capacity shortly after each IPP approached the utility with plans to site

generation. According to these complainants, the utility's reservations enormously

complicated, or precluded the IPPs from reserving point-to-point transmission service

necessary to permit the planned project to go forward. The utility reservations were for

network service designed to accommodate projects in early stages of planning. Such firstin-time reservations receive a priority because of the extended length of the terms

associated with serving network loads. Because the transmission queue was lengthening,

one of the IPPs was forced to get into the transmission queue and had to designate a

delivery point that represented a guess on its part. The IPP made transmission reservation

requests for its proposed site in advance of several probable study phases. It reported to

staff that it is unlikely the project will ever be built because of the numerous requests for

network service ahead of it in the queue. 

A recent Commission decision suggests some of the problems associated with

transmission reservations that IPPs face when seeking to site new generation.31 SkyGen

Energy, an IPP, executed an interconnection agreement with Southern. Southern later

reserved transmission capacity, followed by SkyGen Energy's request for long-term firm

transmission. After conducting a system impact study, Southern denied SkyGen's

transmission request because granting the request would cause an area wide stability

problem. Southern concluded that the only option available for meeting SkyGen's request

would be the construction of a new 80-mile, 500 kV transmission line, and related
32During its recent audit of OASIS sites, staff observed this phenomenon. This

audit, which is referenced in the Midwest report, determined compliance with the OASIS

posting requirements of section 37.6 of the Commission's regulations. 

33See 18 C.F.R. § 37.6(e)(2) (2000). 

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construction that would require approximately 8 years to complete. SkyGen contended that

because the interconnection study agreement pre-dated Southern's OASIS transmission

postings, SkyGen's request for transmission service should be given priority. The

Commission ruled that Southern's transmission request queue is governed by the date that

SkyGen submitted its transmission request and denied SkyGen's request for relief. 

Tactics that exploit plant-siting information that IPPs provide to utilities comprise a

further potential hurdle for IPPs seeking to develop generation resources in the Southeast. 

Possible reforms to address opportunistic load growth reservations by incumbent utilities

could include allowing network requests for transmission service by generators and

limiting self-built capacity in the incumbent utility's service territory. The depth of the

problem posed by reconciling reservation activity by utilities with the expectation of fair

play by IPPs seeking to site new generation plants underlines the importance of RTO

reforms that restore confidence in the fairness of the marketplace. 

B. ATC Issues

As the Midwest report points out, uniform rules do not exist for calculating and

posting ATC. Inconsistent and aberrant ATC postings have posed difficulties to market

participants in other regions in the country and the Southeast is no different in this respect. 

A particularly troubling pattern occurs when a marketer enters a request for transmission

service on OASIS based on the ATC posted there; the request is denied, followed by a large

reduction in the posted ATC.32 Because the reason provided for denial of a transmission

request is often less helpful than the Commission envisioned when it established the

requirement to post a reason,33 the marketer is often left to wonder what happened, as it

scrambles to secure an alternate arrangement. In sum, ATC postings that are not fairly

representative of actual transmission capacity and that fluctuate for no apparent reason

discourage, and raise the costs of, buying and transmitting power in the bulk power market. 

Several utilities in the Southeast indicated that they are active at the regional council

level to coordinate a standardized ATC calculation methodology. This is a long process by

its nature; it may not be resolved soon without direction from the Commission. An

improved method to calculate ATC across service areas is needed. Such an effort, however,

will not address the type of ATC posting deficiency, like the one described above. 

Improved communication by utilities to market participants regarding changes in ATC

postings could allay suspicions that utilities manipulate ATC for competitive gain. 
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C. TLR Issues 

The Southeast experienced a 354-percent increase in TLRs in the summer of 2000

over the summer of 1999. As noted above, the substantial increase in TLRs did not cause

any system-wide price spikes or any area-wide supply disruptions. However, as stated in

the Midwest report, the TLR procedure is an inefficient instrument to use in mitigating

transmission constraints. The Midwest report addresses TLR issues in greater detail. 

The fact that a total of 184 TLRs were declared this summer suggests that the use of

TLRs has been extended from the original purpose of implementing them to address

extreme constrained situations. In fact, the increasing incidence of TLRs since 1999 has

raised the issue of whether curtailment of transmission transactions has become an

impediment to the competitive operation of the market in the Southeast. The high

incidence of TLRs reduces certainty in the market because it frustrates the expectations of

bulk power sellers and their customers. The following discussion addresses specific

concerns regarding TLRs as they bear on the Southeast. 

Whether security coordinators are truly independent and do not favor their

employer-utility has been questioned. As in the case of interconnection access, the built-in

incentive to favor use of the incumbent utility's assets colors the perception of impartiality

of security coordinators in the implementation of NERC's TLR criteria. Staff has not

confirmed that any bias that may exist has been exercised in any specific instance to the

detriment of a market participant, but it cannot discount the possibility that the force of

economic incentives may play a role in TLR implementation.

TLRs are not always implemented according to the criteria established by NERC. 

For example, Ameren Operating Companies' security coordinator implemented a Level 2B

TLR on September 22, 2000. The TLR curtailed a firm transaction, Tag Code 0011194, at

flowgate ID number 3102 (Bland-Franks 345 kV). The sink for the transaction was in

TVA's service territory. Under NERC criteria, firm transmission can only be curtailed by a

Level 5 TLR. Further, the NERC TLR Procedure Log, a historical account of TLR activity,

that provided details regarding this TLR event, failed to disclose that the firm transaction at

issue had been curtailed.

 

The increased incidence of TLRs may suggest that some transmission capacity is

being oversold. Market participants have attributed a tendency to implement a greater

number of TLRs to the commercial reality that transmission providers do not have to

refund transmission reservation fees for service curtailed because a TLR is called. The

extent to which commercial motives influence TLR implementation, if at all, evades easy

verification. Increased Commission oversight in the future in this area may provide insight

to a situation that exists because of the present market structure in the Southeast. 

Development of RTOs may also address these concerns because of the separation of the

operation of transmission and generation resources. Further, the broader geographic reach

that RTOs are intended to have will internalize an increased number of parallel path flows
3-39

and hence reduce the incidence of TLRs. TLRs may also decline because RTOs will adopt

pricing mechanisms to address congestion that will obviate recourse to TLRs. These

developments would be consistent with the experience of the Northeast ISOs. However, as

noted in the Midwest report, RTOs may not necessarily address this problem. To the extent

that control areas are maintained, vertically integrated entities which are members of an

RTO may retain mixed incentives. 

Another way to reduce the incidence of TLRs would be to augment transmission

capabilities. However, regulatory uncertainty, the expense of such an undertaking relative

to financial return to constructing utilities and the prospect of distributed generation

discourage this remedy. 

D. Lack of Information 

A major problem for the markets in the Southeast is lack of information. As the

Commission discussed in Order Nos. 888, 889 and elsewhere, efficient markets require

the free flow of useful information. In the Southeast, it is difficult for market participants

to get key information. As in the Midwest, part of the problem lies in non-compliance with

OASIS requirements. In a staff audit of OASIS sites a number of problems were found. 

First, for both constrained and unconstrained transmission paths, ATC and TTC are often

posted late, if at all. And even if the general methodology of ATC calculation was

described, which is all OASIS requires, market participants seldom have sufficient

information concerning the precise calculation of ATC and TTC to determine whether

particular postings are fair and accurate, and what ATC may be posted in the future. In

addition, curtailments and the reasons for curtailing or for denying transmission service

were not always posted as OASIS requries. There also were problems obtaining or

downloading information concerning transmission service schedules, transmission requests

and services, products and pricing, and tariffs. Moreover, several OASIS audit logs, which

are used to record data and activity on the OASIS site, are not operating correctly and erase

historical data so that it is impossible to audit the sites.

Beyond OASIS, providing greater access to load and transmission line outage data

would increase the certainty of transactions in regional markets in the Southeast. There is

merit in market participants' suggestions that transmission providers should have to post:

sufficient information concerning their transactions with affiliates involving the purchase

and sale of ancillary services and generation imbalance payments to ensure that their

affiliates do not receive preferential treatment; additional ATC that will be available due to

system upgrades that may be made in conjunction with interconnection agreements;

imbalance clearing prices and transmission losses for each control area in real time. 

For a number of reasons, certain information for this study was difficult to obtain

for the Southeast region. Summer 2000 demand data were not readily available. The lack

of Commission transmission jurisdiction over TVA made it difficult to obtain transmission
34TVA News, August 28, 2000.

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access information concerning TVA. As in the case of the Midwest where such allegations

also are common, allegations that transmission providers unjustifiably limited access to

transmission were difficult to verify because individual events often involve complicated

factual situations which require substantial time and resources to examine thoroughly.

Section 5 of the Midwest report discusses information needs of regulators and

market participants. The Commission should refer to this discussion when considering

action to revise reporting requirements. As noted in that section, however, the manner in

which load is calculated weighs heavily on the value of this information. This is an issue

that the formation of RTOs may not resolve. Eliminating native load exemptions—i.e.,

treating all load equally—and placing all transactions under the same tariff may be an

option that provides the right incentives for the provision of transparent and standardized

information. (See section 6 of the Midwest Report.) 

E. TVA Issues

For a number of reasons, the TVA service area is a problem area for the Eastern

Interconnect grid. While they resulted in part from factors beyond TVA's control, the many

TLRs called during the summer of 2000 in the TVA service area indicate that TVA has

become a transmission bottleneck in the Eastern grid. A primary impediment to the

development of deep and robust power markets in this area is the existing federal law which

prevents the free sale of power into and out of TVA because of the TVA fence. Behind that

fence is TVA's generation capacity of 30,203 MW and the TVA service area load of 29,344

MW on a peak basis.34 Another important factor is that TVA is not subject to the complete

extent of the Commission's jurisdiction over interstate transmission service. In the

absence of such jurisdiction, TVA simply does not have a strong incentive to provide

effective and efficient open access transmission service and to address and eliminate seams

issues with neighboring control areas. This is true even though TVA has its Transmission

Service Guidelines which are modeled after the Commission's pro forma open access

transmission tariff. 

Because of the Commission's limited jurisdiction over TVA, the Commission does

not have full access to the information it normally has to determine the extent of

transmission access and other market problems on the TVA system. But from the

information available to the Commission, as also discussed elsewhere in this report, it

appears that TLR, CBM, ATC, and other common transmission problems exist to the same

degree or more on TVA as they do at utilities whose transmission is regulated by this

Commission. TVA is alleged to have: unfairly rejected requests to perform

interconnection studies; required an excessive time, required excessive deposits, and

charged excessive fees to complete interconnection studies when it agreed to do them;

assessed excessive charges for interconnection facilities; required an excessive time to
3-41

process requests for transmission service; given a preference to an affiliate's transmission

request over a prior non-affiliate's transmission request for the same service; incorrectly

rejected a transmission request for failing to specify an NERC control area; provided

transmission capacity for an affiliate when posted ATC was zero; rejected requests for

transmission when ATC was available; allowed TVA Marketing but not other participants to

designate TVA as a sink for transmission service and park power on TVA's system; and

unjustifiably increased its tagging deadline.

Recent proposals by TVA to enhance the development of bulk power markets and the

quality of its open access transmission service do not appear to have great potential. Small

volumes have moved under TVA's “5 percent” program thus far and a number of restrictions

and questionable practices limit the potential effectiveness of that program. For example,

market participants are not provided information on how TVA calculates its “point of

indifference” price, participants must purchase power on a 5-day basis, and are limited to

specific receipt and delivery points. Some problems concerning this program, such as

certain penalties, have been worked out, and discussion continues about others. But even if

the program was fully used, the 5-percent limitation on the amount of outside power that

can be purchased would remain a severe and arbitrary restriction on the free flow of power

and the development of a more efficient and reliable Eastern grid.

F. Florida Law 

Florida law restricts construction of merchant plants. Regardless of the purpose of

the state statutes construed by the state court, granting licenses only to an applicant who has

demonstrated that a utility serving retail customers has a specific need for all of the power

to be generated at the proposed plant severely limits the market mechanisms by which

power may be delivered to loads. In so limiting the generation and delivery of power, it

creates inefficiency by replacing market allocation with administrative determinations. The

Florida decision creates a significant barrier to entry and imposes costs on IPPs that have

made plans to site new generation in Florida that cannot now be brought to fruition. 

G. Standards of Conduct

The Commission's standards of conduct, codified at 18 C.F.R. § 37.4 (2000),

require separation of a utility's transmission function and wholesale merchant function

employees. An FRCC Agent Operational Audit Report, issued September 8, 2000,

contained findings of an apparent violation of the Commission's standards of conduct. 

The report stated that in some instances, confidential reliability information about

Florida Power & Light's (FPL's) transmission system was posted on EMS displays that

were available to` FPL's wholesale merchant affiliate. One such display, for example

revealed the interchange information for other entities. The report concluded that FPL
35FRCC Agent Operational Audit Report, September 8, 2000, at 8. The report may

be found on FRCC's website at www.frcc.com.

3-42

does not have an established procedure for review of EMS displays to ensure that

confidential information does not get displayed in error. Instead, the report states that "[i]t

seems to be up to individual Managers [sic] discretion."35 Violations of the standards of

conduct undermine competition in the wholesale energy market and the industry's

confidence in the integrity of transmission system operations. Staff is unable to determine

at this time whether violations of the standards of conduct are widespread. 

6. Conclusion

In conclusion, a number of inefficiencies exist in the Southeast which are similar to

those that exist in the Midwest. These inefficiencies are exacerbated by the relatively high

amount of IOU-owned generation. Given the inefficiencies discussed above, the

Commission may wish to consider the options set forth at the conclusion of the Midwest

report. 
3-43

Appendix

SERC Regular Members

Investor-Owned Utilities

Alabama Power Co.

Entergy Arkansas, Inc.

Carolina Power & Light Co.

Duke Power Co.

Florida Power & Light Co.

Georgia Power Co.

Gulf Power Co.

Entergy Gulf States, Inc.

Entergy Louisiana, Inc.

Entergy Mississippi, Inc.

Entergy New Orleans, Inc.

Mississippi Power Co.

Nantahala Power & Light Co.

Savannah Electric & Power Co.

South Carolina Electric & Gas Co. 

Tapoco, Inc.

Virginia Power

Yadkin, Inc.

Cooperatives

Alabama Electric Cooperative, Inc.

Associated Electric Cooperative, Inc.

Cajun Electric Power Cooperative

North Carolina Electric Membership

Corp.

Oglethorpe Power Corp.

Old Dominion Electric Cooperative

Sam Rayburn G&T Electric Cooperative,

Inc.

South Mississippi Electric Power

Association

Municipals

Fayetteville Public Works Commission

JEA

Municipal Electric Authority of Georgia

N.C. Eastern Municipal Power Agency

N.C. Power Agency #1

Federal/State Systems

Crisp County Power Commission

South Carolina Public Service Authority

Southeastern Power Administration

Tennessee Valley Authority

Independent Power Producers

Air Liquide America Corp.

Cogentrix Energy, Inc.

LG&E Power Development, Inc.

Enron S.E. Corp.

SERC Associate Members

Investor Owned

Florida Power Corp.

Tampa Electric Co.

Marketers

AES Power Inc.

Aquila Energy Power Corp.

Avista Energy, Inc.

Calpine Power Services Co.

Cargill-Alliant, LLC

Cinergy Corp.

Citizens Power Sales

CLECO Corp.

Conoco Power Marketing, Inc.

Constellation Power Source, Inc.

Coral Power

Delmarva Power & Light Co.

Duke Energy Trading & Marketing

Dynegy Power Marketing Corp.

Enron Power Marketing

Enserch Energy Services, Inc.

Entergy Power Marketing Corp.
3-44

Equilon Energy Services

Koch Power Services 

PECO Energy Co. 

PG&E Energy TradinQ - Power, L

PP&L, Inc.

ProLiance Energy, LLC

Public Service Energy, LLC

Reliant Energy Services

SCANA Energy Marketing, Inc.

SONAT Power Marketing

Southern Energy Marketing, LP 

Tenaska Power Services Co. 

Williams Energy Services Co.

Municipals

City of Tallahassee

Rivera Utilities

FRCC Members

Aquila Power

Citizens Power Sales

City of Homestead

City of Lakeland

City of Lake Worth Utilities

City of Tallahassee

City of Vero Beach

Constellation Power Source

Duke Energy Power Services

El Paso Merchant Energy

ENRON Power Marketing, Inc.

Entergy Power Marketing Corp.

Florida Municipal Power Agency

Florida Power Corp.

Florida Power & Light Co.

Fort Pierce Utilities Authority

Gainesville Regional Utilities

Gulf Power Co.

Indiantown Cogeneration, LP

JEA

Kissimmee Utility Authority

Morgan Stanley Capita'- Group, Inc.

Ocala Electric Utility

Orlando Utilities Commission

PECO Energy Co. - Power Team

Reedy Creek Improvement District

Reliant Energy Services

Seminole Electric Cooperative, Inc.

Southeastern Power Administration

Tampa Electric Co.

The Energy Authority

Utility Board of the City of Key West

Utilities Commission of New Smyrna

Beach

Source: NERC home page at:

http://www.nerc.com/regional/~members.

html