2

OFFICE OF ENFORCEMENT

Division of Energy Market Oversight

August 2009

FEDERAL ENERGY REGULATORY COMMISSION

888 First Street, N.E. Washington, D.C. 

2008 State of the Markets Report

Executive Summary and Overview 3

Section 1 Natural Gas Markets in 2008 25

Section 2 Unconventional Natural Gas Supply 35

Section 3 Cost of New Generation in 2008 41

Section 4 Physical & Financial Bilateral Electricity Trading 47

Section 5 RTO/ISO Capacity Markets 57

Section 6 Natural Gas Capacity Release and Electricity 

Transmission Reassignment 65

Section 7 Market Implications of Natural Gas 

Infrastructure Additions 73
FEDERAL ENERGY REGULATORY COMMISSION

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2008

State of the Markets Report

3

Executive Summary and Overview

Summary of Market Outcomes

Wholesale natural gas and electricity prices rose 

dramatically in the first half of 2008, and then 

fell dramatically through the end of the year. 

On average, electricity and natural gas prices in 2008 

were substantially greater than prices in 2007 in 

virtually every region of the United States. 
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4

Summary of Market Outcomes

Regional differences in spot price changes were largely 

the result of infrastructure issues. For instance, average 

electricity prices at the Minnesota Hub were almost 7 percent 

lower than in 2007, due largely to beneficial hydro imports 

from Manitoba and increased wind generation in western 

MISO. In many hours in 2008, constraints prevented this 

lower-cost power from moving south and east from the 

Minnesota Hub. Gas price changes were affected by new 

pipeline infrastructure. Spot gas prices at Cheyenne Hub 

in the Rockies were 54 percent higher in 2008 relative 

to 2007 due to the inauguration of the Rockies Express 

Pipeline (REX) that allowed Rockies gas, frequently bottled 

up in 2007, to flow to higher-priced midwestern markets. 

This had a cascading effect on surrounding regions that is 

discussed below. 

However, focusing on average prices masks the substantial 

swing in prices experienced during the course of the year. 

Electricity prices for major eastern trading hubs started the 

year in the range of $60/MWh to $80/MWh, rose to between 

$100/MWh to $160/MWh by mid-July, and ended the year 

Figure ES-1 2008 Average Natural Gas Spot Prices

Source: Derived from Platts data, February 6, 2009.
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Figure ES-2 2008 Average On-Peak Electricity Spot Prices

Source: Derived from Platts data.

in the range of $40/MWh to $70/MWh (see Figure ES-3). 

There was a similar pattern in the western United States, 

with the exception of the Mid-Columbia price point, where 

late and robust hydro generation suppressed summer prices 

(see Figure ES-4). 

This dramatic swing in electricity prices was driven by 

equally dramatic swings in fuel prices, principally natural 

gas, coal and oil. Spot natural gas prices at Henry 

Hub started 2008 at $7.83/MMBtu, reached $13.32/

MMBtu on July 3 and ended the year at $5.71/MMBtu 

Figure ES-3

Average Weekly Spot Prices at Eastern Pricing Hubs

Mass Hub

Northern IL

PJM West

Into Southern

Source: Derived from Platts data. 

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

$200

Price ($/MWh)

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Figure ES-4

Average Weekly Spot Prices at Western Pricing Hubs

$0

$20

$40

$60

$80

$100

$120

$140

Price ($/MWh)

Source: Derived from Platts data. 

Palo Verde

SP-15

NP-15

Mid-Columbia

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2008

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(see Figure ES-5). Similarly, Central Appalachia coal futures 

prices rose dramatically from around $55/ton to a high of 

almost $140/ton during the first seven months of the year, 

and then fell back to about $62/ton (see Figure ES-6).

Figure ES-5

Source: Derived from IntercontinentalExchange data. 

$5

$7

$9

$11

$13

$15

Henry Hub Natural Gas Price ($/MMBtu)

1/1 1/15 1/29 2/12 2/26 3/11 3/25 4/8 4/22 5/6 5/20 6/3 6/17 7/1 7/15 7/29 8/12 8/26 9/9 9/23 10/7 10/21 11/4 11/18 12/2 12/1612/30

Henry Hub Daily Spot Prices in 2008 

Figure ES-6 

$0

$20

$40

$60

$80

$100

$120

$140

$160

J FMAMJ J ASOND J FMAMJ J ASOND J

Price (Nominal $/Short ton) 

Central Appalachia

Northern Appalachia

Illinois Basin

Colorado/Utah

Powder River Basin

2007-2008 Regional Coal Spot Prices

Source: Derived from Bloomberg data. 

The remainder of this section will discuss the factors that 

shaped the electricity and natural gas markets during 2008, 

focusing on key themes that emerged over the course of the 

year. These themes include:

•	Physical fundamentals alone can not explain natural gas 

prices experienced during the year. 

•	Unconventional gas supplies and new infrastructure 

have fundamentally altered the nature of natural gas 

markets.

•	The financial crisis that started during the second half 

of the year altered the role of financial energy products 

and financial players in energy markets and increased 

the cost of capital, while simultaneously reducing the 

access to capital.

•	Most electric market outcomes were driven by external 

market forces – specifically, fuel and commodity prices 

and the financial crisis.

•	Alternative energy options, including energy efficiency, 

demand response and wind generation, have emerged as 

key components of electricity markets.

•	The Commission took steps to enhance release and 

reassignment of natural gas transportation and electric 

transmission capacity.

Physical Fundamentals Alone Cannot Explain 

Unprecedented Summer Natural Gas Prices

During the summer of 2008, natural gas prices reached 

high levels never before experienced during the summer in 

the United States. A review of the physical fundamentals 

during the first half of 2008 suggests that supply and 

demand factors alone can not explain why Henry Hub prices 

reached $13.32/MMBtu on July 3 and then tumbled to below 

$6/MMBtu by the end of the year. We discuss various 

physical and financial fundamentals in greater detail in 

Section 2 of this report. The following is a brief overview 

of our findings.
2008

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Supply 

There were no major disruptions to cumulative supply during 

the first half of 2008 that would explain the increase in prices. 

Total gas supply, composed of domestic production and net 

imports, both from Canada and in the form of liquefied 

natural gas (LNG), is estimated to have increased between 

1.3 percent and 3 percent during the first half of 2008 

relative to 2007.1 The increase in cumulative supplies was 

spurred largely by dramatically higher domestic production 

that offset a decline in pipeline imports. Relative to 2007, 

domestic supply is estimated to have been up between 5.8 

percent and 10.1 percent for the first six months of 2008.2 

Demand 

Cumulative gas use through June 2008 is estimated to have 

increased between 2 percent and 3.6 percent relative to 

2007.3 While the growth in consumption during the first 

half of 2008 could have contributed to upward pressure on 

natural gas prices, demand alone does not seem to explain 

the overall level of natural gas prices. This is especially 

true because the growth in demand was concentrated in two 

months (January and March, see Figure ES-7), while spot 

prices continued to rise in April and May.

Figure ES-7

January – June Monthly Gas Consumption 

2006-2008

Source: Derived from EIA data. 

1,000

1,200

1,400

1,600

1,800

2,000

2,200

2,400

2,600

2,800

J F M A M J YTD

Average

Bcf/Month

2006

2007

2008

U.S. Gas Balance

The overall state of the U.S. gas market can be summed 

up through the balance of supply and demand, which was 

not significantly more bullish than the five-year average 

balance, except in January (see Figure ES-8, next page). 

During January 2008, cold weather drove high gas demand, 

resulting in a supply deficit (domestic consumption less 

domestic supply) of 761 Bcf compared to a supply deficit 

of 613 Bcf in January 2007 and a five-year average supply 

deficit of 671 Bcf. However, after January the balance was 

inline with the five-year average. Importantly, there was 

not an exceptional surplus of gas supply in July 2008 when 

prices started to plunge. August does show a significant 

supply surplus due to the low summer demand from power 

generators; however, the market balance was only mildly 

different from the five-year average and the previous two 

years.

1 Bentek Energy LLC is at the lower end of supply growth estimates, while 

Cambridge Energy Research Associates (CERA) and the Energy Information 

Administration (EIA) are at the higher end. Bentek estimates from Energy 

Market Fundamentals - Supply/Demand Balance (Excel Report), EIA estimates 

from Natural Gas Navigator, http://tonto.eia.doe.gov/dnav/ng/ng_sum_

lsum_dcu_nus_m.htm. CERA estimates from North American Natural Gas 

Market Outlook Data Tables, U.S. Lower-48 Gas Supply & Demand Balance, 

http://www.cera.com/aspx/cda/client/report/report.aspx?KID=8&CID=10292

2 EIA reported that gas production grew at 10.1 percent rate during the 

first six months of 2008, while Bentek estimated less robust growth of 5.8 

percent for the first half of 2008 and CERA estimated 9 percent production 

growth for the first half of 2008. Bentek estimates from Energy Market 

Fundamentals - Supply/Demand Balance (Excel Report), EIA estimates 

from Natural Gas Navigator, http://tonto.eia.doe.gov/dnav/ng/ng_sum_

lsum_dcu_nus_m.htm. CERA estimates from North American Natural Gas 

Market Outlook Data Tables, U.S. Lower-48 Gas Supply & Demand Balance, 

http://www.cera.com/aspx/cda/client/report/report.aspx?KID=8&CID=10292.

3 Bentek is at the lower end of consumption growth estimates, CERA estimates 

3 percent growth, and EIA estimates the highest growth. 
2008

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Figure ES-8

 US Gas Supply - Demand Balance 

Source: Derived from EIA data. 

 1000

 800

 600

 400

 200

0

200

400

600

J FMAMJ J ASOND

Bcf/month

2006

2007

2008

Five Year Average

Figure ES-9

Weekly Storage Levels Relative to Five-Year Average

Source: Derived from EIA data. 

-100

-50

0

50

100

150

200

J FMAM J J A S O ND

2008

Bcf

Storage Inventories

Storage levels are often cited as one of the most significant 

indicators of price direction and are another way to examine 

the supply/demand balance. By the middle of January 

2008, storage levels were about 175 Bcf above the fiveyear average. However, storage levels fell to just 109 Bcf 

above the five-year average by the start of February due to 

extremely cold weather. As the winter progressed, storage 

levels continued to fall relative to the five-year average, 

reaching the five-year average by the end of March (see 

Figure ES-9). This decline in storage can certainly explain 

some of the increase in prices during the first three months of 

2008, especially to the extent that storage levels influenced 

market perceptions. 

Storage levels remained at the five-year average through the 

end of May and then dropped to levels in early July that 

the market had not experienced since 2004. Because the 

relatively low storage levels during the price run-up occurred 

in the spring and early summer, when those injecting gas 

have the maximum flexibility in their storage choices, the 

steep price increase likely caused the low inventories. In 

addition, storage remained relatively low throughout July 

and mid-August, though storage was climbing back to the 

five-year average as natural gas prices fell dramatically. 

This suggests that any adverse market perception related to 

low storage levels dissipated quickly. 

While 2008 storage was at or above the five-year average 

most of the year, 2008 prices were far above other periods 

of similarly moderate storage levels. Specifically, higher 

summer storage deficits occurred in the summers of 2000 

and 2003, without a similar impact on summer gas prices 

(see Figure ES-10 on next page).
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Figure ES-10

Relationship Between Henry Hub Weekly Storage 

Decit and Prices, 2008

Source: Derived EIA Weekly Storage Report and ICE data

$0

$2

$4

$6

$8

$10

$12

$14

800 600 400 200 0 200 400 600 800

Storage Surplus (Deficit) Bcf

$/MMBtu

July 2, 2008

2008

2001 2000

2003

The rise in natural gas prices coincided with a global increase 

in many commodity prices. This increase occurred as large 

pools of capital flowed into various financial instruments 

that essentially turned commodities like natural gas into 

investment vehicles.4 Ultimately, we believe that financial 

fundamentals, along with the modest tightening in the 

supply and demand balance during the first part of 2008, 

explain the pattern of natural gas prices during the year.

Natural Gas Market Dynamics

By the end of 2008, natural gas prices were testing 

the bottom of the $6/MMBtu to $8/MMBtu range that 

characterized normal natural gas prices since 2005. By 

March 2009, natural gas prices breached the $4/MMBtu 

that characterized the bottom of the normal range from 

2003 to 2005. The physical factors that drove prices in the 

fourth quarter of 2008 and first quarter of 2009 have the 

potential to fundamentally change the natural gas markets 

over the next few years. Going forward, a key consideration 

is whether natural gas production will be able to get into 

balance with consumption in a manner that will not lead to 

an exaggerated boom-and-bust cycle. 

Production

Natural gas production growth has been concentrated in 

what has been traditionally referred to as unconventional 

gas fields. These fields include tight sands, coalbed methane 

and shale formations. Currently known unconventional 

gas resources are concentrated generally in four areas of 

the United States; the Rocky Mountains (coalbed methane 

and tight sands), the south-central and Gulf Coast region 

(tight sands and shale), the Appalachian region from 

Kentucky to New York (coalbed methane, tight sands and 

shale) and northern Michigan (shale). The EIA estimates 

that unconventional gas totaled 61 percent of Lower-48 

onshore production (11 Tcf) in 2008.5

Unconventional gas plays have become economic due to 

innovations in horizontal drilling and fracturing technology.6

Despite the horizontal drilling and fracturing advances, 

drilling for unconventional natural gas is still relatively 

expensive. Unfortunately, there is limited information 

available on breakeven prices needed to support gas 

development, and the available estimates are disparate.7

 On 

the low end, breakeven prices range from $3.30/MMBtu to 

4 See testimony of Michael W. Masters before the House Committee on 

Energy and Commerce, Subcommittee on Oversight and Investigations, 

United States House of Representatives, June 23, 2008 (“Index 

speculators have poured billions of dollars into the commodities 

futures markets, speculating that commodity prices will increase. ...

assets allocated to commodity index trading strategies have risen from 

$13 billion at the end of 2003 to $260 billion as of March 2008”)

5 Energy Information Administration (EIA), 2009 Annual Energy Outlook.

6 Fracturing refers to the process of using a water, sand and chemical 

composition to break open geological formations that are holding natural 

gas. 

7 Break even prices represent the price level at which producers can cover the 

variable cost of operation and earn an adequate internal rate of return (around 

10 percent).
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$5/MMBtu.8 On the high end, breakeven price estimates for 

most producing basins are in the range from $5/MMBtu to 

$7/MMBtu range.9

Given the plausible range of breakeven prices, spot prices 

at the end of May 2009 are just about $1.50/MMBtu 

below the price needed to sustain drilling activity in most 

unconventional basins. Therefore, any reduction in drilling 

is likely due to attempts to bring supply and demand into 

balance. In fact, drilling activity has fallen dramatically. The 

horizontal rig count (horizontal drilling is used extensively 

to produce shale gas) on June 12, 2009, was 381, down 

166 (30 percent) from a year ago while the total number 

of rotary rigs seeking natural gas was 685, down 921 (57 

percent) from the September 2008 high of 1,606 rigs. That 

said, forward prices for winter 2009-10 and beyond are just 

below the level sufficient to warrant continued drilling.10

From a practical standpoint, a prolonged period of reduced 

drilling activity will make it difficult to retain trained rig 

crews. As rig crew workers move on to take other jobs, it 

will be difficult to hire and train new crews when producers 

want to increase drilling activity.

Infrastructure

A key issue is whether the natural gas market will be able 

to move available low cost supply to consumption centers. 

Natural gas infrastructure burgeoned in 2008. There were 

significant additions in both interstate and intrastate 

infrastructure. Specifically, EIA estimates that new 

interstate and intrastate gas infrastructure projects added 

an unprecedented 43.9 billion cubic feet per day (Bcfd) of 

pipeline capacity in 2008, almost three times the capacity 

additions from previous years.11 Also noteworthy is the 

magnitude of the pipeline projects, with 15 projects designed 

to transport more than 1 Bcfd each.12 

Many of the new pipelines served to better integrate robust 

unconventional natural gas production into the national 

pipeline grid. As a result, some of the most significant 

pipeline capacity additions altered traditional flow patterns 

and transformed physical transportation price relationships. 

These changes were especially noteworthy in the western, 

northeastern and Gulf regions. Increased gas flows from the 

Rockies Express Pipeline (REX) and new shale supplies put 

downward pressure on Midcontinent prices, which were, at 

times, the lowest cost markets in the United States in 2008. 

The separation of prices in Northern and Southern California 

grew by 30 cents, a 64 percent increase from 2007, as Permian 

gas displaced by REX depressed Southern California prices. 

Liquefied Natural Gas 

During 2008, the United States received relatively little 

LNG as prices in the rest of the LNG-importing world were 

higher than U.S. prices. However, world LNG prices have 

fallen substantially since the end of 2008, to the point that 

Northeast prices for natural gas were on par with the rest of 

the world by the end of March 2009 (see Figure ES-11 on

next page).

Additional LNG supplies are coming online and Asian 

and European demand has fallen off. A total of 1.5 Tcf of 

liquefaction capacity should be added to global supply by 

the end of 2009, an increase of approximately 20 percent. 8 Bentek Energy LLC, Bentek Market Alert: Catch the Wave, Part 3, March 3, 

2009.

9 Merrill Lynch Commodities Inc., “Fundamental Shifts for Natural Gas Market,” 

National Association of Regulatory Utility Commissioners Winter Meeting, 

February 2009.

10 According to Bloomberg, forward prices for winter 2009-10 averaged $4.44/

MMBtu at Transco Zone 6 as of June 15.

11 Energy Information Administration, Natural Gas Year-in-Review 2008 http://

www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2009/ngyir2008/

ngyir2008.html#pipeline

12 Ibid.
2008

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Asia accounted for 5.7 Tcf (70 percent) of global LNG imports 

in 2008, and Asian imports could fall by as much as 0.8 

Tcf in 2009 due to the economic recession. This, coupled 

with increasing supply, could free up cargoes to flow to the 

United States and Europe.

Figure ES-11

Atlantic Basin European and United States 

Spot Natural Gas Prices

Source: Derived from Bloomberg and IntercontinentalExchange data. 

$0

$3

$6

$9

$12

$15

$18

J FM A M J

2009

TTF Spot (Netherlands)

Henry Hub Spot 

UK NBP Spot (Britain)

Algonquin Spot

Price ($/MMBtu)

While international export capabilities are increasing, the 

United States has an enhanced ability to receive LNG. The 

commissioning of three new U.S. import terminals (Freeport, 

Sabine Pass and Northeast Gateway) in 2008 increased 

import capacity to 9.3 Bcfd from 3.9 Bcfd. As a result, 

the United States had approximately 40 percent of global 

regasification capacity and was capable of importing 35 

percent of the world’s LNG supply. A large inflow of LNG 

would put substantial downward pressure on natural gas 

prices, especially if demand does not rebound or production 

does not slow.

Financial market turmoil started to affect 

energy markets as early as July

As tumultuous as natural gas prices were during the first 

half of 2008, the capital markets were similarly tumultuous 

during the second half of 2008. As financial institutions 

experienced growing distress, the energy markets were 

affected in two ways. First, trading of financial energy 

products fell and financial institutions took a smaller role 

as energy market participants. Second, energy market 

participants experienced reduced access to and a higher 

cost of capital, resulting in reductions in capital expenditure 

budgets. 

Financial Products and Financial 

Institutions as Energy Market Participants

Prominence of Financial Energy Products

During 2008, financial products continued to play an 

important role in energy markets. The volume of financial 

natural gas trading dwarfs physical natural gas trading. For 

instance, the use of financial basis swaps13 traded on both 

Nymex and the IntercontinentalExchange (ICE) is an order 

of magnitude larger than physical basis volume. Similarly, 

Nymex and ICE futures trading, which is for a term of one 

month, is several orders of magnitude greater than monthly 

physical deals.

This phenomenon continued in 2008, as detailed in Table 

ES-1 on the next page.

13 Basis swaps are instruments that call for the buyer to pay the seller a fixed 

price, and then the seller pays the buyer the difference between the spot price 

for natural gas at two different locations. For instance, on Nov. 1, 2008, a 

Transco Zone 6 New York basis swap for the month of December cost $2.56/

MMBtu. The buyer of the basis swap paid this amount to the seller, and the 

seller then paid the buyer the difference between the Transco Zone 6 New York 

daily spot price and the Henry Hub spot natural gas price, which averaged 

$1.86/MMBtu in December 2008.
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Table ES-1

 Volume Traded (Tcf) 

Product 2007 2008 Percent Change

ICE Bilateral Physical Trading

Daily Fixed-Price 5.67 6.49 14.6 percent

Daily Index 1.54 1.93 25.7 percent

Monthly Fixed-Price 1.74 2.39 37.0 percent

Physical Basis 1.03 1.14 11.1 percent

Monthly Index 1.61 1.89 17.3 percent

Term & Other 0.53 0.27 -50.4 percent

Nymex

Nymex Futures 367.68 494.61 34.5 percent

Nymex Swaps 14.33 13.06 -8.8 percent

Nymex Basis swaps 21.32 18.05 -15.4 percent

ICE Financial

Swing Swaps 4.30 4.61 7.2 percent

Index Swaps 1.01 1.59 57.9 percent

Basis Swaps 20.93 33.63 60.7 percent

Futures Look Alikes 304.24 401.11 31.8 percent

Source: Derived from Nymex and IntercontinentalExchange data

Similarly, in the electricity markets, financial contracts 

continue to play an increasingly prominent role. Starting 

with the third quarter of 2006, financial trading on ICE has 

increased relative to the previous year every quarter until the 

fourth quarter of 2008. At the same time, physical sales of 

electricity, as reported in the Electric Quarterly Report, have 

fallen every quarter relative to the previous year since 4Q04, 

with the exception of 1Q08. 

Financial contracts are especially important in the organized 

electricity markets, where financial contracts on ICE have 

exceeded physical sales reported in EQR that were not made 

to the ISO or RTO. 

Figure ES-12

Majority of Sales in Eastern RTO 

areas to the RTO

Source: Derived from Electric Quarterly Report and IntercontinentalExchange data. 

0

200

400

600

800

1000

1200

1400

1600

1800

MRO NPCC RFC WECC FRCC SERC SPP

TWh

ICE Fin Swaps

Non-RTO Sales (Not Affiliated)

RTO Sales

Eastern RTOs Western States Southeast States

Change in Financial Volumes

The volume of financial energy trading in natural gas and 

electricity markets decreased in the latter part of 2008, likely 

as a result of the financial market turmoil. The clearest trend 

was in electricity. 

The volume of financial electricity products trading on ICE 

started to drop in August 2008 relative to the previous year 

after dramatic increases from January through July (see 

Figure ES-13, next page). This pattern held in most of the 

largest-volume trading hubs. At the two largest trading hubs, 

PJM West and SP-15, 4Q08 trading was down substantially 

relative to 4Q07. Trading volume in 4Q08 was flat relative 

to 4Q07 at several other hubs, such as Mid-Columbia and 

Cinergy, though trading at these hubs during the first part of 

2008 was up substantially relative to 2007.

In the latter half of 2008, FTR auction activity (as measured 

in gigawatts traded in monthly auctions) declined compared 

to the previous year (see Figure ES-14, next page). Financial 

transmission rights (FTRs) are purely financial contracts used 
2008

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to hedge the cost of congestion in regional transmission 

organization (RTO) markets. As financial contracts, they have 

become popular trading vehicles for financial institutions. 

However, the long-term nature of the contracts means that 

collateral requirements associated with FTR positions can be 

substantial. 

Figure ES-13

Strong ICE Financial Power Gains 

Followed by Contraction

Source: Derived from IntercontinentalExchange data. 

0

100

200

300

400

J FMAMJ J ASOND

GWh (Thousands)

2007 2008

47% 81% 63%

79%

38% 21% 30%

-7% 12% -13%-41%

-29%

Figure ES-14

Monthly Financial Transmission Rights 

Auction Activity

Source: Derived from Ventyx Velocity Suite data.

(1) Data reflects monthly auctions in 2007 & 2008 in PJM, MISO, ISO-NE and NYISO.

(2) Net FTR position for an auction month is calculated as the total FTR quantities bought in 

that month less FTRs sold.

0

25

50

75

100

125

150

175

200

225

250

J FMAMJ J A S OND

Auction Month

Net FTR Position (GW)

2007 2008

Increased Trades in 

First Half of 2008

Declining Trades in 

Second Half of 2008

Financial natural gas trading on ICE also declined in the last 

two months of 2008 (see Figure ES-15), though the volume 

of financial trading continued to be an order of magnitude 

larger than physical trading. For the first 10 months, the 

volume of trading across all natural gas products traded on 

ICE was roughly 34 times larger than physical trading. By 

December, that ratio fell to about 22:1. 

Figure ES-15

Monthly Trade Volumes for Natural Gas 

Source: Derived from IntercontinentalExchange data. 

0

10000

20000

30000

40000

50000

60000

J FMAMJ J AS OND

2008

Volume (Bcf)

0

200

400

600

800

1000

1200

1400

1600

Volume (Bcf)

Financial - left axis

Physical - right axis

Role of Financial Entities

The reduction in financial product volumes suggests that 

financial institutions played a progressively smaller role as 

2008 came to an end. We have categorized physical electricity 

sellers into three broad categories – utility, independent power 

producer and financial-marketer – based on the company 

that files the EQR. Based on this determination, we can 

see that much of the drop in physical market activity is the 

result of fewer sales by the financial-marketers category (see 

Figure ES-16, next page). The reduction in physical activity 

by financial institutions and energy marketers is particularly 

evident in the ReliabilityFirst, New England and California 

NERC subregions. ReliabilityFirst is home to PJM and parts 
2008

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of MISO, while New England is home to ISO-NE. All of these 

RTOs operate centralized day-ahead and real-time markets. 

California is home to the California ISO, which operates a 

centralized real-time market.

Figure ES-16

EQR Decline led by Financial Markets Sellers

Source: Derived from from Electric Quarterly Report data. 

0

500

 1000

 1500

 2000

 2500

 3000

 3500

2005 2006 2007 2008

TWh

F/M

IPP

Utility

Cost and Access to Capital and 

Capital Expenditures

Access to and Cost of Capital

By the fall of 2008, the depth of the financial crisis was 

coming into a clearer view. The financial crisis affected 

energy market participants in several ways. First, the 

financial crisis limited the availability of credit. According 

to Southern Companies’ Chief Financial Officer Paul 

Bowers’ statement at the Commission’s January 2009 credit 

conference, “some companies with lower credit ratings 

have not been able to access commercial paper and other 

short-term credit markets.” 14 Mr. Bowers also noted that 

14 Statement of Paul Bowers, Docket No. AD09-2-000, Jan. 13, 2009, page 4. 

“the availability and cost of credit from banks have been 

even more severely impacted due to their financial troubles. 

This is important since many lower rated utilities rely more 

on banks than the capital markets, especially for shortterm financing.”15 Similarly, Arizona Public Service (APS) 

indicated in an Oct. 9, 2008 letter to the Arizona Commerce 

Commission that it also had experienced difficulty accessing 

the commercial paper market, stating that “over the past 

15 months, APS has continuously experienced difficulty 

in accessing commercial paper with the market now being 

completely closed to APS, even though it is currently 

rated as an investment grade borrower (though near junk 

levels).”16 Utility borrowing was down in the third quarter of 

2008 across all rating classifications. In the fourth quarter 

of 2008, A-rated utilities increased borrowing levels, but for 

shorter durations (see Figure ES-17). 

Figure ES-17 

 Amount of Debt Issued (Utilities)

Source: Derived from Bloomberg data. 

0

2

4

6

8

10

12

14

($) Billions

Over 18 Years

9-17 Years

0-8 Years

A BBB Below BBB

 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 2007 2008 2007 2008 2007 2008

For those utilities that have been able to access the credit 

markets, the cost of credit has increased. According to 

Bowers, “ in mid-2008 the credit spread over Treasuries for 

15 Ibid.

16 Arizona Public Service letter to the Arizona Commerce Commission in Docket 

No. E-01345A-08-0172, Oct. 9, 2009.
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the average BBB+ utility was around 50 basis points higher 

than for the average A utility, but this rose to around 100 

basis points near the end of the year. The effect has been 

even more pronounced for BBB- and BBB utilities.”17

Reduction in Capital Expenditures

As a predictable result of the reduced access to capital and 

increased cost of capital, several energy market participants 

have indicated the intent to reduce capital expenditures in 

2009. A survey of 357 oil and gas companies conducted 

by Barclays Capital Resources published in late December 

2008 revealed that 74 percent of the companies said their 

exploration and production (E&P) spending would be equal 

to or less than their total cash flow in 2009. Barclays 

analysts also reported that U.S. E&P spending would drop 

by 26 percent to $79 billion, ending a four-year upturn.18

Independent and smaller producers were affected the most 

while expenditures by the majors and super majors were 

generally flat to 2008. Some of the planned reductions were 

almost certainly related to the fall in natural gas prices and 

the desire to rebalance supply and demand. Nonetheless, 

some of these announcements were also likely related to 

reduced access to capital and the increased cost of capital.

On the electric side, a February 2009 report by the Edison 

Electric Institute indicated that capital expenditure budgets 

have been reduced by about 10 percent for 2009 and 2010.19

Oversight staff’s survey of canceled and postponed generation 

projects indicates that the total capacity of canceled and 

postponed projects through mid-June 2009 is larger than 

the capacity of projects canceled and postponed in all of 

2008. The main reason for the difference was a 50 percent 

increase in cancellations and postponements of coal, natural 

gas and nuclear generation through mid-June 2009 when 

compared to all of 2008. Hydroelectric and wind facility 

capacity, however, was canceled or postponed at a slower 

pace through mid-June 2009, with the amount of capacity 

canceled in 2009 year-to-date 50 percent lower than the total 

2008 value. In 2008, the combined capacity of coal, natural 

gas and nuclear generation represented just over 50 percent 

of the total cancellations and postponements; through midJune 2009 they represent 75 percent of cancellations. Wind 

and hydroelectric represented roughly 32 percent of the 

cancellations and postponements in 2008, but by mid-June 

2009 represent only 17 percent of the cancellations and 

postponements.

Economic Activity and Energy Consumption

According to the National Bureau of Economic Research, 

the United States economy has been in a recession since 

December 2007. However, the effect of the recession on 

consumption of electricity and natural gas has been limited 

to sales to the industrial sector. This is understandable as 

residential and, to a lesser extent, commercial use is driven 

by weather. Overall, electricity sales to ultimate customers, 

as reported to the Energy Information Administration, 

were down about one-quarter of one percent, with sales 

to residential customers down less than 0.2 percent and 

sales to commercial customers up 1.9 percent. Sales to 

industrial customers were down 3 percent, the largest drop 

since 2001, with the substantial decreases starting in June 

17 Testimony of Paul Bowers, Docket No. AD09-2-000, Jan. 13, 2009, page 4.

18 Respondents to the survey indicated that natural gas prices were the leading 

driver of 2009 E&P budget decisions. Similar surveys by Tudor Pickering 

Holt & Co., and Tristone Capital indicated that E&P spending in 2009 would 

decrease 40 percent and 30 percent, respectively.

19 “The Financial Crisis and Its Impact on the Electric Utility Industry,” Julie 

Cannell, Edison Electric Institute, February 2009. Note, a June 2009 update 

suggests that capital expenditures by electric utilities will be flat in 2009 and 

2010. This update is available at http://www.eei.org/whatwedo/dataanalysis/

indusfinananalysis/pages/qtrlyfinancialupdates.aspx
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(see Figure ES-18). Similarly, overall consumption of natural 

gas changed little from 2007, up 0.8 percent. Industrial sector 

demand for natural gas did not start to fall until November 

2008, when it dropped 4.3 percent relative to 2007 (see 

Figure ES-19). 

Figure ES-18

Monthly Industrial Electricity Consumption

Source: Derived from EIA data. 

50000

55000

60000

65000

70000

75000

80000

85000

90000

95000

J FMAMJ J ASOND

GWh

2007 2008

Figure ES-19

Monthly Industrial Natural Gas Consumption

Source: Derived from EIA data. 

0

5

10

15

20

25

J FMAMJ J ASOND

Bcfd

2007 2008

Electricity Market Outcomes Driven 

Largely by External Market Forces

Electricity market outcomes – including spot prices, the 

dispatch order of generating units, the value of FTRs relative 

to realized day-ahead congestion costs and the construction 

of new electric generators – were driven largely by market 

forces outside the electricity market. With the exception of 

the maturation of alternative energy, the electricity market 

was like a boat on the ocean – driven up and down by 

external forces.

Price Outcomes and Dispatch Order

As discussed above, electricity spot prices were driven 

largely by the underlying fuel costs, with typical reactions 

to extreme weather events like the late spring runoff in 

the Pacific Northwest. The dispatch order for generating 

units, particularly in the Southeast and Mid-Atlantic, also 

experienced changes driven by changes in fuel prices. A 

supply curve based on generating unit fuel costs for units 

in the Southeast (SERC) during October 2007 is displayed in 

Figure ES-20. 

Figure ES-20 

Hundred-thousands

 Representative Regional Supply Stack, October 2007

Source: Derived from Energy Velocity data. 

Natural Gas 

Combined 

Cycle Units Oil and 

Natural Gas 

Combustion 

Hydro Turbines

Nuclear

Powder River 

Basin Coal Units 

Eastern Coal Units 

0

20

40

60

80

100

120

140

160

180

Marginal Fuel Cost ($/MWh)

0 1 0 20 30 40 50 60 70
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Historically, natural gas combined cycle plants (dark blue) 

are more expensive than units burning eastern coal (red). 

After natural gas hit record midsummer highs in 2008, the 

price moderated rapidly during the second half of the year. 

On the other hand, central Appalachian coal prices, which 

peaked at $134/ton in early July, descended more slowly, 

remaining above $117/ton into the second week in October 

(spot gas at the Henry Hub was below $7/MMBtu at this 

point). 

As a result of these fuel price dynamics, gas and eastern 

coal-fired units switched positions in the supply stack. This 

caused the realignment of the supply curve in the Southeast, 

which looks much like Figure ES-21. We note, however, that 

coal-fired generation cannot be viewed independently of the 

coal source. The unique characteristics (mining technologies, 

geography and transportation, heat and emissions contents) 

of eastern coal such as Central and Northern Appalachian 

relative to Powder River Basin (PRB) and other western coals 

caused Appalachian coal to rise rapidly in price in recent 

years, whereas PRB coal has stayed in a relatively tight 

and cheap price band in comparison. This has created a 

bifurcated coal stack in which PRB coal units (green) have 

remained lower than eastern-coal units (red), which have 

split higher due to increases in Appalachian coal. 

Figure ES-21

Hundred-thousands

 Representative Regional Supply Stack, October 2008

Source: Derived from Energy Velocity data. 

Natural Gas 

Combined 

Cycle Units Oil and 

Natural Gas 

Combustion 

Hydro Turbines

Nuclear

Powder River 

Basin Coal Units 

Eastern Coal Units 

0

20

40

60

80

100

120

140

160

180

Marginal Fuel Cost ($/MWh)

0 1 0 20 30 40 50 60 70

Table ES-2 below shows the degree to which the change in 

relative cost of eastern coal and natural gas-fired generation 

changed the actual energy generated (as a percentage of total 

thermal generation) in the Southeast NERC subregion.20

Table ES-2

Coal Gen Percent Natural Gas Percent Total Thermal

(GWh) Thermal Gen Gen (GWh) Thermal Gen Gen (GWh)

10/07 13,812 67.2 3,378 16.4 20,568

11/07 12,792 68.7 2,213 11.9 18,613

12/07 13,879 68.3 2,382 11.7 20,305

10/08 11,255 61.5 3,850 21.1 18,291

11/08 11,262 63.0 3,409 19.1 17,880

12/08 12,832 66.3 2,429 12.6 19,360

Source: EPA CEMS data (via Energy Velocity).

Overall, natural gas unit generation in the Southeast 

increased both in absolute generation and share of total 

when compared to a year earlier. On the other hand, coal 

generation during the fourth quarter of 2008 decreased in 

both absolute and percentage terms when compared to one 

year earlier. Again, one must distinguish by source when 

discussing coal. Specifically, from October 2007 to October 

2008, coal units burning Appalachian or a mix of eastern 

coals saw total generation decline between 16 percent and 19 

percent, while those units burning PRB coal saw generation 

decline by only 3.4 percent.

20 The Southeast NERC subregion includes most of Georgia and Alabama (except 

for the extreme northern edges) and the western Florida panhandle and 

southern Mississippi.
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Generation Additions and Cost of New Generation

Longer-term electricity market outcomes were also 

influenced largely by outside forces. Nationwide, during 

2008, electric generating capacity was added at roughly the 

rate experienced since 2005, which is substantially below 

the rate of additions from 2001 through 2003 (see Figure 

ES-22). The moderate additions in new capacity were due 

in part to the fact that many regions of the country enjoy 

healthy reserve margins. 

Figure ES-22

Electric Generation Capacity Additions

Source: Derived from Energy Velocity data. 

0

10000

20000

30000

40000

50000

60000

70000

98 99 00 01 02 03 04 05 06 07 08

MW

Uranium

Petro

Other

Coal

Wind

Gas

In addition, the moderate growth in new capacity is also due 

to the fact that increases in construction input costs and fuel 

prices led to increases in the cost of new generation during 

the year.22 The cost of constructing a new power plant 

increased almost 10 percent during the first three quarters of 

2008, driven by increased costs for specialized labor as well 

as key inputs such as steel and cement. While underlying 

input costs dropped substantially in the fourth quarter, the 

measure of construction costs maintained by Cambridge 

22 FERC staff report, “Increasing Cost in Electric Markets,” June 19, 2008, http://

www.ferc.gov/legal/staff-reports/06-19-08-cost-electric.pdf

FTR Valuations

Similarly, commodity prices also drove much of the value 

of FTRs over the course of the year. PJM, NYISO and ISONE prevailing flow FTRs were collectively overvalued (i.e., 

the auction price was more than the realized day-ahead 

congestion cost) during the first half of the year, while they 

were undervalued during the second half of 2008 (see Table 

ES-3).21 In all of these three markets, realized spot natural 

gas prices during the second half of 2008 were lower, by 

varying degrees, compared to the natural gas futures prices 

that market participants saw at the time of the auction. 

For example, in 2008, market participants in PJM saw an 

average monthly natural gas price of $11.77/MMBtu for the 

July-December period when they were bidding in the FTR 

auction in May. However, spot Henry Hub natural gas prices 

averaged $7.71/MMBtu, or 34 percent lower, in the JulyDecember period. As a result, price differentials across the 

region were compressed. In addition, the convergence of 

operating costs for eastern coal-fired generation and natural 

gas-fired combined cycle plants likely reduced some of the 

typical west-to-east flow.

Table ES-3

FTR Performance as a Hedge in All FTR Markets 

in 6-Month Valuations

 Prevailing Flow FTRs Counterflow FTRs All FTRs

Market Jan-Jun Jul-Dec Jan-Jun Jul-Dec Jan-Jun Jul-Dec

PJM 389.8 -460.4 -55.7 117.0 334.1 -343.4

MISO 20.1 -29.4 47.1 47.4 67.2 18.0

ISO-NE 18.6 -35.0 -1.7 6.1 16.9 -28.9

NYISO 232.3 -2.2 -44.6 8.5 187.7 6.2

Total 660.8 -527.0 -54.8 178.9 606.0 -348.1

Source: Derived from Ventyx Velocity Suite.

Note: Monthly valuation is calculated as the difference between the auction 

clearing price and the actual day-ahead congestion price multiplied by the contract 

amount (in megawatts) for each cleared FTR path. The chart reflects all active 

FTRs applicable to both long- and short-term auctions in calendar year 2008. 

21 For the purpose of this analysis, a prevailing flow FTR is any FTR for which the 

buyer paid to acquire the stream of congestion payments. A counterflow FTR 

is any FTR for which the buyer was paid to take on the responsibility for the 

stream of congestion payments. 
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Energy Research Associates (CERA) held steady (see Figure 

ES-23). CERA attributes the absence of downward pressure 

on construction costs to the backlog of orders held by 

equipment manufacturers and construction companies.23

Commission staff conversations with market participants 

validates CERA’s conclusion. In addition, during the last 

quarter of the year financing costs increased substantially 

and access to capital dried up, as discussed earlier. 

Figure ES-23

 IHS/CERA Power Capital Costs Index 

Source: Derived from Cambridge Energy Research Associates (CERA) data. 

0

50

100

150

200

250

Cost Index (2003=100)

 PCCI with nuclear PCCI without nuclear

03 04 05 06 07 08 08 08

 Q1 Q2 Q4

Emergence of Alternative Energy

While generation additions were modest (at least relative to 

the boom from 2001 through 2003), energy efficiency and 

demand-response programs emerged as a viable option for 

addressing future load growth. Specifically, ISO-NE cleared 

838 MW of new demand-response resources and 798 MW 

of new energy-efficiency resources in its two forward 2008 

capacity auctions. Similarly, PJM cleared 29 MW of new 

demand response in its first forward auction in 2008 and 

662 MW of new demand response in its second auction.

Wind Generation

The generation capacity that was added in 2008 was 

dominated by wind and gas-fired units. Wind capacity 

additions in 2008 were just over 42 percent of new generation 

capacity – just behind gas-fired generation. Wind capacity 

additions were driven in part by state renewable portfolio 

standards and by the renewal of the federal production tax 

credit. Overall, 8,376 MW of wind capacity came online in 

2008, with over half of that total coming from Texas and 

Iowa, and more than 75 percent coming from just seven 

states (see Figure ES-24, next page). The top seven states 

have high wind potential, a renewable portfolio standard 

(RPS), or both. Six of these seven are members of an 

organized market (see Table ES-4, next page).

23 CERA reported in the 2009 Spring CERA Executive Roundtable: CCAF-P 

Market and Index Forecasts (March 19, 2009) Slide 27 entitled “IHS CERA 

PCCI: With and Without Nuclear Update” that the (PCCI) for North America 

for first quarter 2009 dropped 3 percent over the previous six months, the 

PCCI excluding nuclear fell 6 percent over the previous six months. CERA 

attributed the drop in the PCCI to a decrease raw material cost, noting that 

equipment prices (especially highly engineered equipment) had not fallen as 

much as raw material costs.
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Figure ES-24 

Regional Wind Capacity Growth, 1999 - 200͜

Source: Derived from Energy Velocity, Generation data. 

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

99 00 01 02 03 04 05 06 07 08

MW

California

West (Non-CA)

Great Plains

Midwest

Texas

East

During 2008, the Commission took a number of actions to 

improve the backlog in many interconnection queues due 

to wind’s rapid capacity growth. The Commission issued 

interconnection queue reform orders for the Midwest ISO 

(2008),24 California ISO (2008),25 ISO-New England (2009)26

and the Bonneville Power Administration (BPA) (2008).27

Southwest Power Pool’s (SPP) proposed tariff reforms in 

2009 are pending.28

Table ES-4 Top States by Wind Capacity Additions, 2008

 MW wind % U.S. 2008 Wind Potential Cum Rank 

Rank State New Cumulative RPS? ISO/RTO? Top 10 Rank 2008

 1 Texas 2,670 7,116 28% yes ERCOT/SPP yes 2 1

 2 Iowa 1,492 2,790 11% yes MISO yes 10 2

 3 Minnesota 481 1,752 7% yes MISO yes 9 4

 4 Kansas 451 815 3% goal SPP yes 3 10

 5 New York 407 832 3% yes NYISO 15 9

 6 Wyoming 388 676 3% no yes 7 13

 7 North Dakota 369 714 3% goal MISO - partial yes 1 11

 8 Wisconsin 342 395 2% yes MISO 18 15

 9 West Virginia 264 330 1% no PJM 32 17

 10 llinois 216 915 4% yes MISO/PJM 16 8

 11 Washington 212 1,375 5% yes 24 5

 12 Oregon 185 1,067 4% yes 16 7

 13 Indiana 131 131 1% no MISO/PJM 44 21

 14 Michigan 126 129 1% yes MISO 14 22

 15 Montana 125 272 1% yes yes 5 18

 16 Missouri 106 163 1% yes MISO/SPP 20 20

 17 South Dakota 89 187 1% goal MISO - partial yes 4 19

 18 California 78 2,517 10% yes CAISO 17 3

 19 Pennsylvania 67 361 1% yes PJM 22 16

 20 New Hampshire 24 25 0% yes ISO-NE 35 28

Source: Commission staff analysis of data in Energy Velocity, AWEA project database, DSIRE-USA, Pacific NW Lab

24 Midwest ISO, 124 FERC ¶ 61,183 (2008).

25 California ISO, 124 FERC ¶ 61,292 (2008).

26 ISO – New England, 126 FERC ¶ 61,080 (2009).

27 Bonneville Power Authority, 123 FERC ¶ 61,264 (2008). BPA files Open 

Access Transmission Tariffs (OATT) and amendments to meet the Commission 

standards for reciprocity approval.

28 Southwest Power Pool Inc., Docket No ER09-1254 (submitted June 1, 2009).
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Midwest ISO (MISO) reforms include increased fees for queue 

entry, increased commitments to stay in the queue and 

prioritization of more mature projects. In addition, MISO 

instituted three levels of deposits that scale up with the size 

of the proposed projects. CAISO reforms include adopting 

a clustering approach to process interconnection requests 

for projects in the same area, paring down the number 

of studies needed, and increasing and accelerating the 

financial commitments required for an entity to participate 

in the interconnection process. The Commission approved 

BPA’s proposed network open season similar to that used 

by gas pipelines to address its queue and to determine the 

transmission additions necessary to accommodate committed 

generation projects. 

The Commission also approved NYISO’s proposal to 

implement a centralized forecast program for energy output 

from interconnected wind plants. A specialized third-party 

forecasting company collects data every 10 minutes, which 

the forecasting company submits every 15 minutes to the 

ISO. As a result, NYISO now integrates wind output into its 

real-time security-constrained dispatch.29

Effects of Credit Crisis and Economic 

Downturn on Wind Generation

Renewable projects usually have high construction costs and 

low operating costs. Historically, developers partnered with 

tax equity investors – large investment banks or insurance 

companies – that used specialized financing structures to 

capitalize on federal tax credits or accelerated depreciation. 

The credit and financial crises that began in summer of 2008 

profoundly affected renewable project financing. Active 

equity partners from the financial services sector shrank from 

as many as 18 in early 2008 to as few as 4.30 As investors 

and developers lost money and had less taxable income, taxbased incentives were less attractive or ineffective.31 While 

wind projects set all-time installed capacity records in 2008, 

the financing for most projects completed in 2008 was set 

before the economic turndown. 

The effect of the financial crisis on new wind capacity 

became more apparent in early 2009. Some ISOs and RTOs 

reported slowdowns in interconnection requests, although 

noting it was difficult to determine how much was due to 

queue reform and how much was economy-related.32 Edison 

International, the seventh largest owner of wind generation, 

deferred all wind turbine deliveries and associated payments 

save one in the first quarter of 2009.33 Solar companies 

and wind turbine component manufacturers laid off some 

workers.34 

Ancillary Services and Demand Response

The Commission took a number of actions during 2008 to 

enhance the ability of demand-response resources to provide 

ancillary services. Most notably, it issued Order No. 719 in 

October 2008.35 Among other things, Order No. 719 directed 

each RTO or ISO to accept bids for ancillary services from 

technically capable demand-response resources in a manner 

comparable to other resources.

29 New York Independent System Operator, 123 FERC ¶ 61,267 (2008) 

30 Chadbourne & Parke, tax and project finance specialist, quoted in the New 

York Times, Feb. 4, 2009. 

31 National Renewable Energy Laboratory (NREL), PTC, ITC, or Cash Grant?, March 

2009, page 1, and Stanford Group, Wind Outlook, Dec. 8, 2008, page 13. 

32 ERCOT announced multiple monthly drops in interconnection requests. (SNL 

Energy, June 10, 2009. 

33 Edison International, 10-Q Securities and Exchange Commission filing, May 8, 

2009. Edison International owns wind generation through its Edison Mission 

Energy subsidiary.

34 “Dark Days for Green Energy,” The New York Times, Feb. 4, 2009.

35 Wholesale Competition in Regions with Organized Electric Markets, Order No. 

719, 73 Fed. Reg. 64,100 (Oct. 28, 2008), FERC Stats. & Regs. ¶ 31,281 (2008).
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The Commission separately issued orders for market rule 

changes in several markets. For instance, the Commission 

issued an order this year in which it conditionally accepted 

NYISO-filed tariff revisions that allow demand-side resources 

to offer operating reserves and regulation service on terms 

comparable to generators.36 In MISO, the Commissionapproved ancillary services market (ASM) that began on Jan. 

6, 2008, includes demand-response resources. MISO permits 

nondispatchable demand-response resources to provide 

energy and contingency reserves in the day-ahead and realtime markets and permits dispatchable resources to provide 

the same services as well as regulation service.37

In its 2008 State of the Markets Report, PJM’s market 

monitor Monitoring Analytics noted that “throughout 

2008, the MW contribution of demand-side response 

resources to the synchronized reserve market remained 

significant and resulted in lower overall synchronized 

reserve prices.”38 Monitoring Analytics went on to say 

that during 2008, demand-side resources accounted for all 

cleared tier 2 synchronized reserves in 27 percent of hours 

when a synchronized reserve market was cleared.39 In the 

hours when all supply was from demand-side response 

resources, the unweighted average price was $2.58/MW. By 

comparison, the unweighted average synchronized reserve 

price for all cleared hours was $8.49/MW. 

Renewable Portfolio Standards

State renewable portfolio standards have been an important 

driver behind new wind generating capacity. A renewable 

energy portfolio standard (RPS) requires a load-serving 

entity (LSE) to procure either a fixed percent of energy sales 

(MWh) or installed capacity (MW) from renewable resources.

The requirement usually increases incrementally from a 

base year to an ultimate target. Overall, 29 states, including 

the District of Columbia, have a renewable mandate, while 

an additional 6 have renewable goals without financial 

penalties. 

Figure ES-25

States with Renewable Portfolio Standards in 2008

RPS

Strengthened/ amended RPS

Voluntary standards or goals

Proposed RPS or studying RPS

Other renewable energy goal

Source: Derived from EEI, EIA, LBNL, PUCs, State legislative tracking services, 

DSIREUSA, Pew Center and the Union of Concerned Scientists.

A number of states took action during 2008 to start or 

expand the state’s renewable portfolio standard: 

•	Three states passed a new RPS (Ohio, Michigan and 

Missouri).40 

36 New York ISO, 123 FERC ¶ 61,203 (2008).

37 Midwest ISO, 122 FERC ¶ 61,172 (2008).

38 Monitoring Analytics, LLC, 2008 State of the Markets Report, March 11, 2009, 

page 300. 

39 Tier 2 resources include units that are backed down to provide synchronized 

reserve capability, condensing units synchronized to the system and available 

to increase output, and demand response resources that can reduce their 

electricity consumption within ten minutes. 40 Ohio enacted a hybrid RPS-EERS that includes 12.5 percent of retail sales 

(MWh) from renewable energy by 2025, with a solar set-aside (0.5 percent). 

Energy reduction standards are separate. Michigan’s RPS replaces a goal for 

one utility only; it is a 10 percent capacity requirement by 2015. Missouri’s RPS 

is for 15 percent of retail sales by 2021. 
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•	Three jurisdictions accelerated the time to achieve an 

established RPS or increased the capacity or energy target 

in an existing RPS (Washington, D.C., Maryland and 

Massachusetts).41 

•	Three states with an existing RPS set goals beyond their 

mandates (Maine, California, Hawaii), and one with a 

renewable goal increased it (Vermont).42

•	Four states adopted a voluntary RPS or renewable goal 

(South Dakota, Utah, Kansas and Florida).43

In addition to a renewable portfolio standard, some states 

also have an energy efficiency resource standard (EERS) (see 

Figure ES-26). An EERS is designed to reduce or flatten 

electric load growth through energy efficiency (EE) measures. 

Goals may specify reductions in energy (MWh), demand 

(MW) or both. At least 18 states include energy efficiency 

as part of a renewable standard or goal. During 2008, 14 

states passed significant energy efficiency legislation or 

regulations.44

Figure ES-26

States with Energy Efficiency Resource Standards, 2008

EE only as part of an RPS law, rule, or goal

EERS by regulation or law (stand-alone)

Voluntary standards (in or out of RPS)

Energy efficiency goal proposed / being studied

Other energy efficiency or demand-side rule or goal

Sources: Derived from ACEEE, EPA, Regulatory Assistance Project, Union of 

Concerned Scientists, State regulatory and legislative sites; State Efficiency

Agency reports; trade press

Transparency Efforts Bear Fruit

The Commission has taken several actions in the past 

few years to enhance the use of natural gas and electric 

transmission capacity by reforming the rules by which 

existing transportation service can be released or reassigned. 

These actions include removing the price cap on released 

transportation service and requiring electric transmission 

service customers to report reassignments of transmission 

service.

Order No. 712, which became effective July 30, 2008, removed 

the rate ceiling on short-term capacity releases on interstate 

natural gas pipelines.45 The order also modified the capacity 

release rules to facilitate the use of asset management 

41 Washington, D.C., increased its RPS from 11 percent by 2022 to 20 percent by 

2020, with solar set-aside (0.4 percent); Maryland increased from 9.5 percent 

in 2022, with 2 percent solar, to 20 percent by 2022 with (same) solar set-aside 

(2 percent); and Massachusetts increased its RPS from 4 percent by 2009 with 

1 percent subsequent annual increases to 15 percent by 2020.

42 Maine enacted an installed wind goal of 3,000 MW by 2020 (April). California 

issued an executive order setting a 33 percent by 2020 goal beyond the 20 

percent by 2010 mandate (November). Hawaii’s Clean Energy Initiative, agreed 

to by the governor and utilities, set a goal of 40 percent by 2030 of energy 

from renewables beyond its 20 percent by 2020 goal (January). Vermont 

increased its goal to 25 percent by 2025; its goal had been that incremental 

load growth from 2007 to 2012 should come from renewables (March).

43 South Dakota and Utah enacted goals without noncompliance penalties. A 

memorandum of understanding between the governor of Kansas and Kansas 

utilities created its goal. Florida’s goal, via executive order, is for utilities to 

produce 20 percent from renewable energy. 

44 District of Columbia, Florida, Hawaii, Iowa, Massachusetts, Maryland, Michigan, 

New Jersey, New Mexico, New York, Pennsylvania, Ohio, Oklahoma, Utah and 

Vermont. 45 Promotion of a More Efficient Capacity Release Market, Order No. 712, 73 Fed. 

Reg. 37,058 (June 30, 2008), FERC Stats. & Regs. ¶ 31,271 (2008).
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24

agreements (AMAs), removing certain prohibitions on tying 

arrangements and bidding. 

Commission staff has developed a set of initial observations 

of the first six months of the Commission’s revised capacity 

release rules. Because of the seasonal nature of the natural 

gas market, capacity releases during this period were 

compared to those of previous years during the same sixmonth time frame. The period covers, primarily, the winter 

and the months leading up to it. Shorter-term decisions 

about whether to release capacity for a day or a month are a 

function of weather conditions, and are therefore as dependent 

on immediate circumstances as on pricing conditions. LDCs, 

for example, would be less likely to release capacity in the 

face of uncertain winter weather. Longer-term decisions to 

release capacity for a year or more tend to occur at or near 

the beginning of the gas year in April as a function of longterm planning within the natural gas cycle.

The early experience from the capacity release reforms 

suggests that there has been relatively little change in 

capacity release activity. This is partially because the period 

of study includes the winter and the months leading up to it 

when shippers are less likely to release capacity in the face 

of uncertain winter weather.

On the electric side, market participants that had reserved 

transmission service have been allowed to reassign that 

service above the tariff rate since Order No. 890 went into 

effect during the second quarter of 2007.46 Order No. 890 

also requires that electric transmission providers report 

in their quarterly EQR filings reassignment of TSRs for 

service reserved under the transmission providers open 

access transmission tariff. The requirement is designed to 

promote transparency in transmission markets, similar to 

the requirement that natural gas pipeline companies post 

capacity releases on their pipelines.

There has historically been relatively little reassignment 

of electric transmission service. Since the second quarter 

of 2007, the quantity of transmission service that has 

been reassigned has increased steadily. This increase in 

reassignments occurred across almost all dimensions. 

That is, the number of transmission providers reporting 

reassignments has increased; the number of TSRs reassigned 

for each particular duration (e.g, hour, daily, monthly, 

yearly) has increased; and the capacity (in MWh of service) 

reassigned has increased. Capacity reassignments occurred 

throughout the non-RTO markets, with no particular region 

standing out. The majority of completed TSR reassignments 

were for less than a day, though on a MWh-basis yearly 

and monthly reassignments comprise the vast majority of 

reassignments.

We are unable to fully address the pricing of TSR 

reassignments because many entities reassigning TSRs failed 

to report a price

Organization of this Report

The remainder of the report will discuss a number of specific 

topics in depth. These topics include:

•	 the physical and financial fundamentals that drove 

natural gas prices during the year;

•	 the effect of unconventional gas supplies and liquefied 

natural gas on future natural gas market dynamics;

•	 physical and financial electricity trading;

•	 the cost of new electric generating capacity and the role 

of demand response and energy efficiency in addressing 

capacity needs;

•	 the growth in new natural gas infrastructure and the 

resulting change in regional gas flows and prices;

•	 electric capacity auction outcomes; and

•	 early outcomes from Commission reforms to enhance 

release and reassignment of natural gas transportation 

and electric transmission capacity.

46 Market participants that have reserved transmission service have been 

allowed to reassign that service reservation since Order No. 888 initiated the 

Commission’s current electric transmission service regime.
2008

State of the Markets Report

FEDERAL ENERGY REGULATORY COMMISSION

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25

Section 1 Natural Gas Markets in 2008

Perhaps the most significant event in U.S. natural gas 

markets in 2008 was the large swing in prices. Spot prices 

began 2008 at $7.16/MMBtu, peaked at $13.31/MMBtu 

on July 3 and then collapsed precipitously, ending the year 

at $5.71/MMBtu.

While physical fundamentals can explain why natural gas 

prices rose during the first half of the year, none of the 

physical fundamentals were extreme enough to explain 

the high level that natural gas prices reached. 
State of the Markets Report

26

State of the Markets Report

www.ferc.gov/oversight

Introduction

Our review of physical fundamentals during the first half 

of 2008 suggests that supply and demand factors alone 

cannot explain the 86 percent spike in natural gas prices. 

Nonetheless, a number of discrete events, which we describe 

in detail below and summarize in Figure 1, put upward 

pressure on prices and contributed to the perception of 

market tightness during the first half of 2008. In the second 

half of 2008, a number of discrete events put downward 

pressure on prices and combined to dispel the perception 

that the natural market was tight. 

All of the discrete events identified in Figure 1 ultimately have 

to have acted through the balance of supply and demand. The 

overall balance of supply and demand through June 2008 

was not significantly more bullish than the five-year average 

balance, except in January. Importantly, though the August 

surplus was large, there was not an exceptional surplus of 

gas supply in July when prices started to fall dramatically. 

Therefore, with the exception of January and August, the 

overall supply and demand balance was unexceptional.

A review of natural gas markets in 2008 is not complete 

without an analysis of financial market fundamentals, 

including the unprecedented increase in financial gas product 

open interest in 2008 and technical trading strategies that 

can, in the extreme, induce commodity bubble-like markets 

outcomes.

The past few years have seen a large influx of passive 

investments, primarily from institutional investors, into 

commodities in general. Beginning in the second half of 

2007, the fall in equity values and rising commodity prices 

helped push investors into commodities in search of higher 

returns.1

 A year later, the financial crisis and subsequent 

failure of several large trading firms reduced liquidity and 

likely contributed to the deflation of the gas price. 

nts 

res 

ent 

Figure 1

Source: Derived from IntercontinentalExchange data. 

Henry Hub Bidweek Physical Event Financial Event

1

5 6

4

3

2 2

6 5 4

3

1

15

10

8

9

19

7

13

14

20

11

1216

17

18

$5

$7

$9

$11

$13

$15

Henry Hub Natural Gas Price ($/MMBtu)

1/1 1/15 1/29 2/12 2/26 3/11 3/25 4/8 4/22 5/6 5/20 6/3 6/17 7/1 7/15 7/29 8/12 8/26 9/9 9/23 10/710/2111/411/1812/212/1612/30

Signicant Events in U.S. Gas Markets in 2008

2008 Physical Events

1 04-01 Storage falls to a 5-year average

2 04-08 Independence Hub shut down removes 900 

MMcfd through June 3rd

3 06-01 Warm temperatures spark high power demand 

and storage is below 5 year

4 06-01 NOAA forecasts 18 named storms, 10 hurricanes, 

and 6 intense hurricanes

5 07-30 Independence Hub shuts down through August 7th

6 08-29 Gulf production shut in due to Gustave and Ike

Source: Derived from ICE

 2008 Financial Events

1 02-05 Buying and selling CDOs grind to a halt

2 02-14	 UBS	confirms	sub-prime	loss	of	18.4	B

3 02-21 Credit Suisse announce a $1.2 B loss for 4Q07

4 03-16 Bear Sterns collapse leads to purchase by JP Morgan

5 04-02 UBS writes down $19 B in losses

6 04-24 Credit Suisse announce a $2.1 B loss for 1Q08

... Table continued on next page

1 The need to offset declining equity returns through commodity investme

is discussed in “Absolute returns in commodity (natural resource) futu

investments,” Hilary Till and Jodie Gunzberg, Chapter 3, Hedge Fund Investm

Management (Elsevier 2006)
State of the Markets Report

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State of the Markets Report

7 09-07 Government seizes Fannie Mae and Freddie Mac 

8 09-15 Lehman brothers bankruptcy

9 09-15 Merril Lynch sold to Bank of America

10 09-16 Barclays purchases Lehman

11 09-16 AIG Bailout

12	 09-16	 Goldman	Sachs	reports	a	70%	drop	in	profits

13 09-16 Japan’s Nikkei Index closes 570 points

14 09-16 Constellation stock falls 25%

15 09-18 Central banks aroun the world pump $180 B in the 

system

16 09-29 Dow Jones falls 777 points, the most ever

17 09-29 Bailout package rejected

18 09-29 Constellation stock falls 40%

19 10-01 U.S. economic bailout passed by the federal 

government

20 10-13 British government unveils $37 B banking bailout

Source: Derived from ICE

In addition to the role of passive money in commodities, 

we believe that some of the increase in natural gas prices 

was the result of market perceptions and technical trading 

strategies. These technical trading strategies include the 

tendency of commodity traders to trade in a manner that is 

consistent with the prevailing price movement. Thus, some 

technical traders buy as the price is moving up and sell as 

the price is moving down. 

Oversight staff believes that the physical and financial markets 

did not act in isolation during 2008, but rather influenced 

one another and were influenced by the expectations and 

perceptions of market participants (Figure 2). This interaction 

between physical and financial markets likely occurs most 

of the time. However, during 2008 the end result of this 

interaction resulted in prices that were substantially out of 

balance with the underlying physical fundamentals.

In the remainder of this chapter, we will review in detail the 

physical and financial fundamentals during 2008.

Figure 2

Natural gas prices influenced by physical and financial 

fundamentals and market perception

Physical Fundamentals

Market Perception

Price

Physical Fundamentals

Prices 

Between 2003 and 2007, spot natural gas prices at the Henry 

Hub settled into a $6 to $8/MMBtu trading range from which 

prices deviated only for readily identifiable events, such as 

the 1-Tcf loss of Gulf Coast production due to hurricanes 

Katrina and Rita in 2005, or a spike in gas demand due to 

winter weather. During 2008, spot natural gas prices rose 

far outside their normal range, peaking at $13.31/MMBtu 

on July 3. Prices subsequently collapsed back to the $6-to-

$8/MMBtu range through the summer and continued to fall 

below this trading range into 2009 (see Figure 3 on next 

page). 

Financial Fundamentals
State of the Markets Report

28

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State of the Markets Report

Figure 3

Henry Hub Natural Gas Daily Spot Prices 

2007, 2008 and First Quarter of 2009 

Source: Derived from IntercontinentalExchange data. 

$0

$2

$4

$6

$8

$10

$12

$14

 J F M A M J J A S O N D J F M A

Spot Gas Price at Henry Hub 

$/MMBtu

Gas Price Peaks at $13.31/MMBtu on July 2

2003 - 2007 Trading Range

2008 2009 

U.S. Supply-Demand Balance

The overall balance of gas supply and demand provides 

a summary of prevailing fundamentals in the U.S. gas 

market. The difference between demand and supply is 

made up by either withdrawals from or injections into gas 

storage. Overall, the supply-demand balance in 2008 was 

unexceptional and not particularly strained. 

We will summarize key developments in supply and demand 

individually, and then discuss the overall supply-demand 

balance.

Supply

Notwithstanding several discrete events, there were no major 

disruptions to supply during the first half of 2008 that would 

explain the large increase in prices observed. Total gas 

supply, composed of domestic production and net imports 

[both from Canada and in the form of liquefied natural gas 

(LNG)], is estimated to have been up between 1.3 percent 

and 3 percent during the first half of 2008 relative to 2007.2

 For 

the entire year, gas supply is estimated to have been between 

0.8 percent and 3.2 percent higher than 2007.3

 The growth in 

domestic supply was driven by tremendous growth in domestic 

production, which was partially offset by lower imports, both 

from Canada and LNG.

EIA reports that gas production grew at a rate of 10.1 percent 

during the first six months of 2008 and at 7.7 percent for the 

year. Bentek reports less robust growth of 5.8 percent for the 

first half of 2008 and 3.6 percent for the year, while CERA 

reports 9 percent production growth for the first half of 2008 and 

7 percent for the year (Figure 4). Growth occurred despite the 

loss of approximately 900 MMcfd of production through the new 

Independence Hub, which shut down for repairs between April 8 

and June 2, 2008, for a total loss of 46 Bcf.

Figure 4

US Natural Gas Production, 2006, 2007, and 2008

Source: Derived from Bentek data. 

40

45

50

55

60

65

J FMAM J J A S O ND

Bcfd

2008 2007 2006

Hurricane Gustav

Hurricane Ike

Although the hurricane season was the most active in 64 years 

with a total of 16 named storms, all the storms occurred after 

prices had begun falling from their July peak. Prices continued 

2 Bentek is at the lower end of supply growth estimates, while CERA and EIA are 

at the higher end.

3 Bentek estimates 2008 supply growth of 0.85 percent, CERA estimates 2 

percent and EIA estimates 3.2 percent.
State of the Markets Report

29

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State of the Markets Report

to fall as the season unfolded, even in the wake of hurricanes 

Gustav and Ike, which resulted in a loss of almost 7 Bcfd of 

production in September 2008 – and, according to the Minerals 

Management Service (MMS), with more than 404 Bcf of 

production lost as of February 2009. In 2005, hurricanes Katrina 

and Rita shut in almost 8 Bcfd of production and wellhead prices 

more than doubled. By comparison, in 2008 the hurricanes had 

little impact on prices, which declined by more than $2/MMBtu 

during September and October. Price declines in the face of lost 

Gulf Coast production indicate the degree to which the surplus 

in productive capacity loomed over the market in the latter half 

of 2008. 

Responding to high prices, the gas rig count climbed through 

2007 and the first half of 2008, from 1,425 operating rigs 

on December 29, 2006, to over 1,600 operating rigs in the 

final week of August. The rig count fell precipitously as gas 

prices plunged, ending the year at 1,267 operating rigs.

Offsetting the increase in gas production, net pipeline 

imports fell by more than 1 Bcfd (12 percent) during 2008 

to approximately 7.3 Bcfd. Bentek Energy data show that 

pipeline-gas imports from Canada into the Midwest were 

down 12.5 percent on the year at 3.1 Bcfd. Imports of 

Canadian gas into the West were down 3.9 percent, at 2.6 

Bcfd, and imports into the Northeast were down 5.3 percent, 

at 2.5 Bcfd. At the same time, exports to Mexico surged 15.6 

percent in 2008, averaging 900 MMcfd, almost 1.5 percent 

of total U.S. daily consumption. 

The increase in domestic gas production was also partially 

offset by lower imports of LNG. Average daily LNG imports 

fell to less than 1 Bcfd in 2008 from 2 Bcfd in 2007. The 

peak decline was actually much larger, since average 

monthly LNG sendout (the flow of regasified LNG from the 

terminal into the pipeline system) peaked at 3.2 Bcfd in April 

2007 compared to 1.3 Bcfd in July 2008. Diversion of LNG 

cargoes from the United States to other ports in the world 

began in September 2007, when a severe earthquake shut 

down Japan’s 8,200-MW Kashiwazaki-Kariwa nuclear power 

plant and Japan began bidding away spot LNG cargoes 

to run gas-fired generation. Diversion of cargoes to Asia 

intensified in 2008 as oil prices rose to more than $140/

bbl. This caused oil-linked LNG spot prices in Asia to rise 

to over $20/MMBtu, almost twice as high as U.S. gas prices. 

Delays and disruptions to supply in countries as diverse as 

Nigeria, Norway and Algeria removed supply from the global 

market. Spain, the second largest importer of LNG, boosted 

LNG imports to make up for poor hydroelectric conditions. 

While most LNG terminals (including Cove Point, Md., Lake 

Charles, La., and the new terminals) experienced sporadic 

sendout as a result of these market conditions, two terminals 

– those at Elba Island, Ga., and Everett, Mass. – maintained 

sendout levels relatively well because each had long-term 

contracts with suppliers. 

Figure 5

Monthly US LNG Imports and Import Capacity, 

2007 -2008

Source: Derived from Waterborne LNG data. 

-

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

Average Bcf/d

Freeport LNG, TX

Sabine Pass, LA

Northeast Gateway, MA

Cove Point, MD

Lake Charles, LA

Elba Island

Everett

Import Capacity

July 16, 2007 Earthquake damages Japan's 

8.2 GW Kashiwazaki-Kariwa nucelar plant 

forcing shut down

5.4 Bcfd of US LNG 

regasification capacity 

added in 2008

J-07 M M J S N J-08 M M J S N

Demand

Notwithstanding several discrete events, demand growth 

during the first half of 2008 cannot explain the degree of 

increase in prices. Driven by cold weather in January and 

associated high residential and commercial gas demand, gas 
State of the Markets Report

30

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State of the Markets Report

use through June 2008 increased between 2 percent and 3.6 

percent relative to 2007.4 This demand was easily met by a 

combination of production, imports and withdrawals from 

storage. In the second half of the year, growth in gas use 

was cut by low summer demand for power generation and 

the deepening economic recession, resulting in overall 2008 

growth of less than 1 percent, with some estimates suggesting 

a modest decline.5 Annual growth in gas consumption in 

2008 was much lower than the 6.4 percent growth recorded 

in 2007.

Figure 6

Year-on Year Change in Gas Consumption 

for 2008

Source: Derived from EIA data. 

-250

-200

-150

-100

-50

0

50

100

150

J F M A M J J A S O N D

Bcf/Month

Residential/Commerical

Industiral

Electric

Weather is one of the key drivers of natural gas consumption. 

Other than June, which was warmer than normal, national 

weather was cooler than normal through most of the spring, 

summer and fall. A very cold January and the cold fall 

contributed to residential and commercial gas consumption 

growth of 3 percent in 2008 (see Figure 6). According 

to the National Weather Service’s population-weighted 

temperatures, cooling degree days in August 2008 were 20 

percent less than in August 2007. Due to the unseasonably 

mild August, power plants consumed 22 percent (nearly 7 

Bcfd) less gas than in August 2007 (see Figure 7). From a 

regional perspective, moderate increases in gas use for power 

generation in the West and Gulf regions were offset by even 

larger declines in the Northeast, Southeast and, especially, 

the Midwest. 

Figure 7

Daily Gas Consumption for Power Generation

Source: Derived from Bentek Energy data. 

0

5

10

15

20

25

30

35

40

J FMAM J J A S O ND

Bcfd

2007 2008

U.S. industrial output grew 1.4 percent during the first 

quarter of 2008 compared to the first quarter of 2007. With 

the onset of recession, U.S. industrial output fell 0.4 percent 

in the second quarter, 3.2 percent in the third quarter and 

6.7 percent in the fourth quarter. Mirroring the decline in 

industrial output, U.S. industrial gas use grew at a robust 

4.4 percent during the first quarter of 2008, slipping to 

3.1 percent growth in the second quarter. The deepening 

recession resulted in declines of 0.6 percent and 4.1 percent, 

respectively, during the third and fourth quarters, with 

industrial gas use showing only 0.5 percent growth for the 

year. 

4 Bentek is at the lower end of consumption growth estimates, CERA estimates 

3 percent growth, and EIA estimates the highest growth 

5 For 2008 Bentek estimates an annual decline in consumption of 0.4 percent, 

EIA estimates no growth, and CERA estimates growth of less than 1 percent.

Supply-Demand Balance
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State of the Markets Report

Supply and demand do not work in isolation. Rather, the 

overall balance of supply and demand dictates the relative 

tightness of the natural gas market. Figure 8 illustrates the 

supply-demand balance for 2006, 2007 and 2008. Other than 

January 2008, the balance was in line with than the five-year 

average. Importantly, there was not an exceptional surplus 

of gas supply in July 2008 when prices started to plunge, 

although the August surplus was significantly greater than 

the five-year average because of low summer demand from 

power generators. 

Figure 8

 US Gas Supply - Demand Balance 

Source: Derived from EIA data. 

 1000

 800

 600

 400

 200

0

200

400

600

J FMAMJ J ASOND

Bcf/month

2006

2007

2008

Five Year Average

Storage Remained Close to 

Five-Year Average for Most of 2008

Gas in storage remained close to the middle of the fiveyear range for most of 2008. Figure 9 shows that at the 

beginning of 2008, inventories were well below the January 

2007 levels, but near the middle of the five-year range. 

However, January 2008 was the coldest January in four 

years, resulting in a record drawdown in storage. As a 

result, U.S. gas inventories fell significantly behind those 

in 2006 and 2007, but managed to remain in the middle of 

the five-year range and above the five-year average. As the 

winter progressed, storage levels continued to fall relative 

to the five-year average, reaching the five-year average by 

the end of March. Between March and June, gas storage 

was roughly at the five-year average, briefly dipping below 

during June due to high temperatures and a surge in demand 

from gas-fired power generation. Oversight staff notes that 

much of the period of relatively low storage levels occurred 

in the spring and early summer of 2008, when those injecting 

gas had the maximum flexibility in their storage choices. 

As a result, the steep price increase likely caused the low 

inventories experienced in the first half of 2008. 

Figure 9

Total U.S Working Gas in Storage 

Source: Derived from EIA data.

0

500

1000

1500

2000

2500

3000

3500

4000

A M J J A S O N D J F M

Volume (BCF)

2003-2007 range

2006-2007

2007-2008

2008-2009

Inventories began to surpass their five-year average in August 

at the same time that prices began to fall. As production 

grew and demand moderated due to the deepening economic 

recession, storage began to move up to the higher end of the 

five-year range. By the end of first-quarter 2009, storage had 

almost recovered to the upper end of the five-year range. Of 

particular note, storage levels in January 2009 were almost 
State of the Markets Report

32

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State of the Markets Report

identical to storage levels in January 2008, though prices 

moved in the opposite direction in 2008 and 2009. 

The degree of price pressure from storage is illustrated by 

Figure 10, which shows the difference between weekly 

storage and the moving five-year average versus the gas 

price at the Henry Hub in 2008 $/MMBtu. The years 2000, 

2001 and 2003 are illustrated because they indicate historical 

periods with substantial deficits and high prices. During 

2008, storage was at or above the five-year average most 

of the year. The deficit peaked at only 70 Bcf in early July, 

compared to deficits 10 times that in previous years. Even 

so, prices increased to more than $13/MMBtu by July 2008. 

Higher summer deficits occurred in the summers of 2000 and 

2003 without a similar impact on summer gas prices. 

Figure 10

Relationship Between Henry Hub Weekly Storage 

Decit and Prices, 2008

Source: Derived EIA Weekly Storage Report and ICE data

$0

$2

$4

$6

$8

$10

$12

$14

800 600 400 200 0 200 400 600 800

Storage Surplus (Deficit) Bcf

$/MMBtu

July 2, 2008

2008

2001 2000

2003

Financial Fundamentals

Connection Between Physical and 

Financial Natural Gas Prices

Financial natural gas prices provide a basis for the formation 

of physical natural gas prices. Prior to growth in the use 

of natural gas futures, swaps and other derivatives, market 

participants established short-term natural gas price 

expectations by assessing physical supply and demand 

conditions. With the growth of trade in natural gas 

financial derivatives since the early 1990s, financial markets 

have played a growing role in the price discovery process. 

For example, trading on the Globex electronic exchange 

takes place around the clock, and physical traders will 

often look at recent prices to help determine their bid-ask 

values at the beginning of the trading day (8 a.m. on the 

IntercontinentalExchange [ICE] and 9 a.m. on the New York 

Mercantile Exchange [Nymex]). This is similar to the way 

stock traders look at European and Asian stock markets and 

at stock futures to ascertain U.S. stock price direction at the 

beginning of each trading day. 

The prices of futures, swaps and other financial instruments 

are now used by physical markets to form price indexes. 

Likewise, financial markets attempt to determine prices by 

looking at data on fundamentals that often are not confirmed 

until well after the fact. This lack of real-time transparency 

can lead to misperceptions that lead to skewed price signals 

and prices that can over- or undershoot underlying values 

based on the physical fundamentals. An example of this 

occurred in 2008, when many market observers missed the 

extraordinary growth in unconventional gas production. 
State of the Markets Report

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State of the Markets Report

Key Financial Fundamentals

The two key financial fundamental drivers of natural gas 

prices in 2008 were the large influx of passive investments 

into commodities and technical trading strategies based on 

trading around the prevailing market momentum. 

The past few years have seen a large influx of passive 

investments, primarily from institutional investors, into 

commodities in general and natural gas in particular 

through vehicles such as exchange-traded funds (ETFs).6 In 

May 2008, Michael Masters, portfolio manager for Masters 

Capital Management LLC, reported in his testimony before 

the House Committee on Energy and Commerce that assets 

allocated to commodity index trading strategies rose from 

$13 billion at the end of 2003 to $260 billion by March 

2008 and that this increase helped drive commodity prices 

higher. He also reported that natural gas purchases by 

passive investors in commodity index funds increased from 

331 Bcf equivalent at the beginning of 2003 to more than 

2,263 Bcf equivalent by the first quarter of 2008, an increase 

of 1,932 Bcf equivalent.7

Passive investment in commodities is not manipulation, 

nor is it necessarily bad for market outcomes. Passive 

investors and active speculators can enhance price signals 

to producers and consumers that energy markets are tight 

by bidding up prices, in effect magnifying the impact on 

prices of underlying fundamentals. Such a phenomenon 

likely contributed to the rapid rise in gas prices and other 

commodities during the first half of 2008 and the subsequent 

collapse of commodity prices during the second half of the 

year. 

Figure 11 shows that commodity prices started trending up 

in unison in late 2007 and peaked in early July 2008. From 

Jan. 1, 2007, until July 6, 2008, prices of crude oil, natural 

gas and corn grew 237 percent, 215 percent and 191 percent, 

respectively, while gold increased by 150 percent. Prices 

subsequently fell back to Jan. 1, 2007, levels by November 

2008 and, by March 31, 2009, commodity prices had fallen 

to as low as 55 percent below their Jan. 1, 2007, values.

Figure 11

Cross Commodity Price Index 

(January 1, 2007 = 100)

Source: Derived from Bloomberg Exchange data 

0

50

100

150

200

250

Crude Oil Natural Gas

Gold Corn Index

 J M M J S N J M M J S N J M 

2007 2008 2009

In addition to the role of passive money in commodities, 

we believe that some of the increase in prices was the result 

of market perceptions and technical trading strategies. 

These technical trading strategies include the tendency of 

commodity traders to trade in a manner that is consistent 

with the prevailing price movement. Thus, some technical 

traders buy as the price is moving up and sell as the price is 

moving down. For instance, trader commentary on July 2, 

the day the natural gas price peaked, expressed this sentiment 

as 

“the old worn out cliche says it the best; the trend is 

your friend. The market is still trending higher and will 

continue to do so until somebody finally says they are 

going to stop buying it. In futures, we are advising 

people that they have to hold their nose and continue 

to buy and sell this thing because we don’t know how 

high it is going to go.”8

 

6 The ETF market has grown to over 600 ETFs since their inception in 1993. 

7 As a comparison, U.S. gas consumption was 23,157 Bcf in 2008, so passive 

investment in natural gas via commodity index was almost 10 percent of total 

consumption. 

8 “Broker: ‘ Trend Is Your Friend’ As Futures Edge Above $13.50”, NGI’s Daily Gas 

Price Index, page 2, July 2, 2008 
2008

State of the Markets Report

FEDERAL ENERGY REGULATORY COMMISSION

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34

Similarly, a contemporaneous commentary by a Barclays 

analyst describes this phenomenon as “momentum trading,” 

stating that “(t)he same trends responsible for increasing 

bearish sentiment in the financial markets have in many 

cases opened the door to profits for momentum-based futures 

traders.”9

These strategies result in the accumulation of long positions 

as prices increase and the accumulation of short positions 

as prices fall. Figure 12 shows that average monthly open 

interest in the natural gas prompt month climbed 109 percent 

to 106,000 contracts in summer 2008 from 50,759 contracts 

in 2006. At the same time, average monthly natural gas 

prompt prices climbed 38 percent to $12.78/MMBtu in 

June 2008 from $9.23/MMBtu in 2006. As prompt month 

gas prices fell to $5.74/MMBtu at the end of the year, open 

interest fell 25 percent. 

Figure 12 

Natural Gas Prompt Month Open Interest 

and Price

Source: Derived from Nymex data 

0

20

40

60

80

100

120

Contracts (Thousands)

3

5

7

9

11

13

15

$/MMBtu

Open Interest for the Gas Prompt Month

Price of Gas Prompt Month

 

 J M S J M S J M S J

 2006 2007 2008 2009

9 http://www.barclayhedge.com/blog/2008_07_01_archive.html

Conclusion

While physical market fundamentals, particularly relatively 

low gas in storage, explain part of the rise for both futures 

and spot gas prices, there’s no physical explanation for 

prices in the $13 range. However, the rise in gas prices did 

coincide with a global increase in many commodity prices, 

which occurred as large pools of capital flowed into various 

financial instruments, turning commodities such as natural 

gas into investment vehicles. Oversight staff believes that it 

was the upward pressure of financial fundamentals on top of 

a modest tightening in the supply-and-demand balance for 

gas in first-half 2008 that explains the path of natural gas 

prices during the year.
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Section 2 Unconventional Natural Gas Supply

The extent to which unconventional natural gas sources are 

economically recoverable became much more apparent during 

2008, fundamentally changing the natural gas markets. In 

the near-term, a key consideration is whether natural gas 

production will be able to balance with flagging consumption in 

a manner that will not lead to an exaggerated boom-bust cycle. 

Robust unconventional domestic gas supplies (and increased 

liquefied natural gas [LNG] imports) creates an environment 

in which natural gas will no longer be considered a scarce 

resource, particularly at prices above $5-$6/MMBtu.
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The Expanding Natural Gas Resource Base

Recently, the long-term outlook for natural gas supplies in 

the United States changed dramatically. It was previously 

assumed that U.S. productive capacity would continue to 

drop (to 50.1 Bcfd in 2006 from 53.6 Bcfd in 2001) in the 

face of steep declines in production in the Gulf of Mexico 

and Lower-48 states. However, recent estimates conclude 

that 2008 full-year U.S. dry gas production rose 4 Bcfd (7.7 

percent) to 56.2 Bcfd from 2007, despite more than 404 Bcf 

of lost production in the Gulf due to well shut-ins caused 

by hurricanes Gustav and Ike in 2008.1

 Strong growth 

in unconventional gas production in East Texas and the 

Rocky Mountain region, supplemented by new deepwater 

production in the Gulf of Mexico (e.g., Independence Hub, 

Atlantis and Thunderhorse) have prompted the reversal of 

the trend. 

More generally, recent technological progress has made 

unconventional gas economic to develop in sufficient 

quantities so that unconventional gas plays are now 

transforming the nation’s gas supply picture.2 Overall, EIA 

estimates U.S. gas reserves, which consists of gas available 

from known reservoirs capable of being produced with 

reasonable certainty under existing economic and operating 

conditions, were 238 Tcf at the end of 2007, 13 percent more 

than at year-end 2006 and the highest level in the 31 years 

1 Energy Information Administration, Natural Gas Navigator, Dry Gas Production, 

http://tonto.eia.doe.gov/dnav/ng/ng_prod_sum_dcu_NUS_a.htm.

2 A play is a set of known or postulated natural gas accumulations sharing 

similar geologic, geographic and temporal properties, such as source rock, 

migration pathway, trapping mechanism and hydrocarbon type.

The Geography of Shale Resources

Source: Energy Information Administration, based on data from various published studies. Updated May 29, 2009.
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that EIA has published annual reserves data ( see Figure 13). 

EIA attributed the growth principally to the rapid development 

of unconventional gas resources, including shale, coalbed 

methane and tight, low-permeability formations. Shale 

proved reserves, in particular, increased 50 percent in 2007 

and now account for about 9 percent of the U.S. total.3

In 2007, 46 Tcf of reserves were added, twice the level of 

production, and 2008 could be another banner year. 

Figure 13

U.S. Gas Reserves, 1974 – 2007 

Source: Derived from EIA data. 

0

50

100

150

200

250

Tcf

74 76 78 80 82 84 86 88 90 92 94 96 98 00 02 04 06

The supply boom appears sustainable. Technically 

recoverable gas, a broader estimate than natural gas reserves 

(which it includes), now exceeds 2,200 Tcf.4 The Potential 

Gas Committee (PGC), housed at the Colorado School of 

Mines, just reported a year-end 2008 estimate of the total 

available future supply of 2,074 Tcf, an unprecedented 

biennial increase of 35 percent from its year-end 2006 

estimate of 1,532 Tcf and the highest resource estimate in 

PGC’s 44-year history. The 2,074-Tcf supply includes 1,836 

Tcf of technically recoverable resources plus the Energy 

Information Administration’s (EIA) assessment of 238 Tcf of 

proved natural gas reserves. Proved reserves include gas 

that can reasonably be expected to be recovered in future 

years from known reservoirs under existing economic and 

operating conditions. The volumes of both proved reserves 

and technically recoverable gas have risen with vast increases 

in unconventional supplies such as shale gas. 

The EIA estimates that unconventional gas (shale gas, 

coalbed methane and tight-sands gas) accounted for 61 

percent of Lower-48 onshore production (11 Tcf) in 2008.5

Cambridge Energy Research Associates (CERA) estimates 

that unconventional gas production will constitute 66 

percent of U.S. productive capacity by 2018.6 While shale 

gas plays garner the headlines as the source of incremental 

supplies going forward, tight-sands gas makes up the bulk 

of unconventional gas production, about 40% according to 

the EIA. This growth of unconventional supplies means that 

natural gas is no longer scarce (see Figure 14).

Figure 14

Composition of Estimated U.S. 

Dry Gas Production, 1996 - 2009

Source: Derived EIA 2009 Annual Energy Outlook data. 

0

2

4

6

8

10

12

14

16

18

20

Tcf

Unconventional

Conventional

96 97 98 99 00 01 02 03 04 05 06 07 08 09

5 Energy Information Administration (EIA), 2009 Annual Energy Outlook.

3 U.S. Crude Oil, Natural Gas and Natural Gas Liquids Reserves 2007 Annual 6 A World of Potential-The Unconventional Revolution of Natural Gas, CERA, 

Report, Energy Information Administration, February 2009. September 2008.

4 North American Natural Gas Supply Assessment, Navigant Consulting, July 4, 

2008. 
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Figure 15 

Estimated Annual Unconventional 

Dry Gas Production, 1996 - 2009

Source: Derived from EIA 2009 Annual Energy Outlook data. 

0

2

4

6

8

10

12

Bcf (Thousands)

Shale

Tight Sands

Coalbed Methane

96 97 98 00 02 04 06 

One surprising market phenomenon is the sustained natural 

gas production in the face of an economic downturn, falling 

commodity prices and crumbling rotary and horizontal 

rig counts since September 2008. Production can be 

maintained due to the nature of unconventional gas wells; 

favorable economics in unconventional plays, the high 

initial production rates typical of such wells and the sheer 

numbers of unconventional wells drilled to exploit each 

play. In addition, some producers continue to drill wells in 

more promising unconventional plays like the Haynesville 

(in east Texas and west Louisiana) and Fayetteville (in 

Arkansas) shales, but are not completing the normal 

multistage fracturing process.7

 These producers continue to 

drill to satisfy lease requirements but cap the well, waiting 

for higher commodity prices before beginning production.

Figure 16

Unconventional Gas Yields

Source: Derived from Bentek Energy LLC data. 

0

1

2

3

4

5

6

7

8

9

10

First Month Average 

Production (MMcf/d) 

(Thousands)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

% Decline in Active Rigs 

From 2008 Peak

First Month Average Production

% Rig Decline From 2008 Peak

21. Permian-NM

22. San Juan

23. Anadarko-KS

24. Appalachian-NY

25. Raton

 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 

8. Green Rover-Overthrust

9. Texas Gulf Coast-Onshore

10. Ft. Worth

11. Appalachian-WV

12. Anadarko-TX

13. Arkoma-Woodford

14. Piceance

15. Wind River

16. Anadrko-OK

17. Uinta

18. AL-MS-FL

19. Appalachian-KY-East

20. Permian-TX

1. ARKLA - Haynesville 

2. Appalachian-PA-South

3. Arkoma - Fayetteville

4. Appalachian-PA-North

5. Louisiana Gulf Coast

6. East Texas

7. Paradox

Figure 16 depicts the percentage decline in rig activity from 

the peak week in 2008 (red bars) and first month average 

production by supply basin (blue bars). 8 On examination, two 

issues become apparent. First, many of the new shale plays 

exhibit outstanding productivity. Producers are reporting 

initial production rates from 5 MMcfd to 20 MMcfd, much 

higher than initial production rates from normal conventional 

wells (1 MMcfd to 3 MMcfd). Second, rig activity in the 

more productive plays (read superior economics) is declining 

the least. The data illustrate anecdotal evidence that many 

producers have reduced drilling activity (especially in the 

7 Horizontal drilling (a technical innovation begun in the 1930s) and multistage 

hydraulic fracturing (begun in the 1950s) are used to maximize production 

while minimizing both cost and surface disturbance. In this process, a vertical 

well is drilled several thousand feet down to a shale gas deposit. Then the drill 

bit is turned 90 degrees to follow the shale horizontally. This lateral wellbore 

may run 1,000 feet to 6,000 feet (Department of Energy; Deutsche Bank), 

with fracturing (or frac) stages every 500-700 feet started by puncturing the 

wellbore, allowing pressurized fracturing fluid (water, chemicals and proppant) 

to enter the shale and crack it open. As DOE’s National Energy Technology 

Laboratory (NETL) noted in a shale gas primer, “Stages are fractured sequentially 

beginning with the section at the farthest end of the wellbore, moving uphole 

as each stage of the treatment is completed until the entire lateral well” 

has been tapped. There can be eight or more of these stages, which can be 

completed by a producing company on a schedule to economically maximize 

its output. This whole process minimizes cost and surface disturbance. 

“Complete development of a 1-square mile section could require 16 vertical 

wells each located on a separate well pad,” NETL said. “Alternatively, six to 

eight horizontal wells (potentially more), drilling from only one well pad [using 

only one rig], could access the same reservoir volume, or even more.” Thus, 

multiwell drilling from one pad and multistage fracturing from each horizontal 

wellbore can vastly increase natural gas production compared with traditional 

vertical drilling.

8 Rig activity is through April 17, 2009.
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Rockies) and reallocated capital to those plays with high 

initial production rates even as they reduce overall capital 

expenditures.9

Costs

These unconventional gas plays have become economic 

(compared to years past) due to innovations in horizontal 

drilling and fracturing technology. Unfortunately, there is 

limited information available on the prices needed to cover 

operating and capital costs, including a reasonable return on 

investment, and the available estimates are disparate. On the 

low-end, Bentek Energy LLC recently compiled well-cost data 

from company reports and presentations to derive breakeven 

prices for some of the major plays in the range of $3/MMBtu 

to $5/MMBtu. On the high-end, breakeven price estimates 

for most producing basins are in the range of $5/MMBtu to 

$7/MMBtu. Figure 17 illustrates the range in estimates of 

breakeven prices for many of the major unconventional gas 

plays in the United States.10

Several factors suggest that unconventional production is 

possible even at current low spot prices.11 First, although 

spot prices were below $4/MMBtu at the end of April 2009, 

forward prices at the Henry Hub were averaging almost $5.50/

MMBtu for the November 2009 through March 2010 winter 

strip. Thus, based on forward prices, most unconventional 

plays are economic. Second, field services costs and steel 

costs are falling (down more than 50 percent from last year’s 

highs), as are rig day rates (down about 25 percent), thereby 

allowing the low-cost plays to remain competitive. 

Figure 17

Estimated Breakeven Costs

Source: Derived from Bentek Energy LLC, and Fundamental Shifts for Natural Gas Market, 

National Association of Regulatory Utility Commissioners Winter Meeting, Merrill Lynch 

Commodities Inc., February 2009 data. 

$2.88 $3.16 $3.60 $4.00 $4.02 $4.04 

Bentek

Merrill Lynch

$5.50 $5.50 $6.00 $4.50 $5.50 $6.00 

HaynesvillePinedale

 /Jonah Fayetteville Marcellus Piceance Barnett

$0

$1

$2

$3

$4

$5

$6

$7

The long-term viability of unconventional gas appears to 

be sound, as unconventional plays tend to hold large, longlived reserves. The production profile generally exhibits 

high initial production rates, a rapid decline over the first 

year,12 followed by a long, low-level production life - in 

some cases in the vicinity of 20-30 years at very steady 

flow rates. In addition, though it commonly costs at least 

$2 million to $3 million to drill a horizontal shale well,13

they are less risky than conventional wells. Specifically, 

9 For example, Bentek Energy said that Questar and EnCana have publicly 

announced they are quitting operations in some plays in the Rockies and 

reallocating capital to the Gulf region shale plays; Chesapeake is reducing 

capital expenditures in the Barnett Shale to concentrate on its Haynesville 

Shale leases : “Bentek Market Alert: Catch the Wave, Part 3,” March 3, 2009.

10 The costs include lease operating expenses, royalty rates, gathering and 

transportation, severance taxes and finding and development costs, and an 

assumed internal rate of return of 10 percent.

11 In a recent presentation at the NARUC 2009 Winter Meeting held on Feb. 

17, 2009, Tom Price, senior vice president for corporate development at 

Chesapeake Energy Corp., presented data showing that much of the shale 

industry would have virtually risk-free finding and development costs of 

between $1-$3/MMBtu for decades to come .

12 In Tarrant County, Texas, in the Barnett Shale, a vintage 2007 well lost 59 

percent of peak production in 12 months. “Natural Gas Weekly Kaleidoscope,” 

Barclays Capital, page 3, Dec. 9, 2008.

13 “Shale Gas Outside of North America-High Potential but Difficult to Realize,” 

CERA, page 4, April 2009. CERA speaking to the cost to drill shale gas wells in 

North America. Further, CERA stated costs could range as high as $6 million 

per well. 
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gas in shale occurs in widespread, continuous layers where 

virtually any well drilled into the shale will produce gas 

and much of it in commercial volumes; once a productive 

area is identified, additional wells can be targeted at the 

same depth in the formation to maximize production. The 

producer then concentrates on the correct process, well 

spacing, fracturing fluid and fracturing technique for the 

play. Though it took a few years to mature, the spectacular 

development in the Barnett Shale is a prime example of a 

successful unconventional drilling program. 

Issues Affecting Development

Land use and environmental issues must be addressed to 

assure effective unconventional gas production. The primary 

concern to date appears to be related to water use issues. 

Unconventional gas plays need large amounts of water to 

fracture the formations. In addition, extraction of coalbed 

methane produces large volumes of water during the coal 

formation dewatering process before natural gas can be 

produced. These are important issues to all stakeholders and 

could pose significant challenges to further unconventional 

gas development. 
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Section 3 Cost of New Generation in 2008

Despite the fact that prices of raw materials needed 

to build a new power plant plummeted in the latter 

part of 2008, the cost of building a power plant did 

not materially fall. 
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Introduction

As the summer of 2008 approached, Commission staff 

became concerned that electricity prices for the remainder of 

the summer and possibly far into the future were increasing 

rapidly. 1 The outlook for electricity prices increasing into 

the future was due to both dramatically increasing fuel prices 

and the growing cost to build new generation. Starting in 

July, the price of natural gas, oil, steel and copper, along 

with a slew of other commodities, fell steadily. This drop in 

commodity prices seemingly reduced the upward pressure 

on electricity prices. However, despite the fact that the price 

of many raw materials fell, the price of finished equipment, 

such as turbines, reactors and boilers, did not follow suit. 

In addition, the credit and financial crisis began soon 

after the crash in commodity prices had commenced. The 

financial crisis simultaneously raised the cost of capital to 

fund investment in new generation and reduced the access 

to capital. Thus, just as one source of pressure (physical 

construction costs) on long-term electricity prices was 

seemingly reduced, another source of pressure (financing 

costs) was growing. Together, this left the total cost of 

building power generation by the end of 2008 close to where 

it was in June. 

Thus, while forward prices for electricity had fallen by about 

50 percent from June to December, primarily due to the fall 

in fuel prices, the cost of constructing new generation had 

not materially changed. This leaves open the possibility that 

future increases in fuel prices could lead to concerns similar 

to those that arose in June 2008. At the very least, persistent 

high cost for new generation can lead to uncertainty, and 

result in delayed additions to the generation fleet.

Companies may be delaying expenditures of any kind 

that are not pressing due to the increased cost of debt. In 

addition, investors that expect the cost of new generation to 

fall further may defer investment in new power generation as 

they wait for costs to fall further. These types of expectations 

can have a self-fulfilling nature as market participants defer 

investment in new generation, which reduces demand for the 

inputs used in building new generation (i.e., raw materials, 

major equipment, labor and financing), and thus creates 

downward pressure on the costs to build new generation. 

This uncertainty regarding the cost to build new generating 

capacity highlights the potential role for demand-side 

resources to fill the void. This is especially true for demandside resources with costs that are well below the current 

estimates of the levelized cost of new thermal generation.

The remainder of this section will review 

•	 the dynamics of the physical cost 

to build new generation;

•	 the changes in the cost and availability of credit; and

•	 the potential for demand-side resources to fill the void.

1 FERC, Divison of Energy Market Oversight. “Increasing Costs in the Electric 

Market.” Federal Energy Regulatory Commission, June 19, 2008. http://www.

ferc.gov/legal/staff-reports/06-19-08-cost-electric.pdf.
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Physical Construction Costs in 2008

Figure 18

 IHS/CERA Power Capital Costs Index 

Source: Derived from Cambridge Energy Research Associates (CERA) data. 

0

50

100

150

200

250

Cost Index (2003=100)

 PCCI with nuclear PCCI without nuclear

03 04 05 06 07 08 08 08

 Q1 Q2 Q4

Cambridge Energy Research Associates (CERA) produces the 

Power Capital Costs Index (PCCI) that tracks the costs of 

materials, major equipment and construction labor needed 

to build new power plants.2 The PCCI nearly doubled from 

2003 to mid-2008. Much of this cost increase resulted from 

elevated costs of raw materials and scarcity in specialized 

equipment and labor for this type of construction. However, 

there have been two systemic changes in the economy since 

mid-2008. First, commodity prices fell substantially, and 

second, the credit crisis led to reduced access to and high cost 

of capital. According to the PCCI, the cost of constructing 

nonnuclear power plants first declined in the fourth quarter 

of 2008, while the cost of constructing all power plants, 

including nuclear power generation, first decreased in the 

third quarter.3

 It is important to note that the PCCI does not 

include costs associated with financing.

Figure 19

Primary Raw Materials

Source: Derived from Bureau of Labor statistics website data. Base year adjusted to 2003. 

75

100

125

150

175

200

225

250 Iron and Steel 

Cement 

GDP Def 

 7 1 7 1 7 1 7 1 7 1 7

 03 04 04 05 05 06 06 07 07 08 08

While the nonnuclear PCCI fell only about 1 percent from 

the third quarter to the fourth quarter of 2008, steel prices 

fell precipitously - by over 34 percent - from August 2008 to 

December 2008. Even though steel prices fell dramatically 

from where they were in August 2008, as of December 2008, 

they were still 65 percent higher than January 2003 prices.4

Correspondingly, the non-nuclear PCCI was 60 percent higher 

than in January 2003. Copper was yet another commodity 

that experienced a price spike in mid-2008. Copper prices 

quintupled in nominal value between 2003 and mid-2008, 

but by the end of 2008, prices had fallen back down and, 

compared to 2003, had merely doubled.5 Wages have not 

2 Cambridge Energy Research Associates, Capital Costs Analysis Forum – Power: 

North America: Impacts of the Financial Turmoil, March 6, 2009.

3 On March 19, 2009, CERA reported a drop of 3 percent in the cost of 

constructing all new power plants from the last quarter of 2008 until the 

first quarter of 2009, and a drop of 6 percent in the cost of constructing nonnuclear power plants. CERA attributes this further decline to the persistence 

of lower steel, copper and petroleum prices, even as equipment prices remain 

sticky. This was reported at the 2009 Spring CERA Executive Roundtable in 

CCAF-P Market and Index Forecasts (March 19, 2009) Slide 27 entitled “IHS 

CERA PCCI: With and Without Nuclear Update”. 

4 U.S. Bureau of Labor Statistics. Iron and Steel: WPU101. ONLINE. 2009, http://

www.bls.gov/data/.

5 U.S. Bureau of Labor Statistics. Copper: WPU102301. ONLINE. 2009, http://

www.bls.gov/data/.
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noticeably dropped since the June 2008 presentation.6 One 

reason for this may be that the recession resulted in more 

layoffs than wage reductions. 

Figure 20

Secondary Raw Materials

Source: Derived from Bureau of Labor statistics website data. Base year adjusted to 2003. 

50

100

150

200

250

300

350

400

450

500

550

Copper 

Aluminum 

Nickel 

Zinc 

GDP Def 

 1 7 1 7 1 7 1 7 1 7 1 7

 03 03 04 04 05 05 06 06 07 07 08 08

While the price of raw materials fell in the second half of 

2008, the prices of finished equipment, such as turbines, 

reactors and boilers, did not significantly decline. There are 

several reasons that the lower prices of raw materials did 

not result in noticeably lower prices for finished equipment. 

First, there was a significant backlog of orders, and because 

manufacturers of these finished products were working 

through those backlogs, they were not seeking to book new 

business and lock in potentially disadvantageous prices.7

Second, it is possible that manufacturers made concessions, 

such as promotional discounts, that would camouflage 

declining prices. 

Credit Crisis

For years, the majority of electric utilities have moved from 

having an A credit rating to having a BBB credit rating.8

This trend continued in 2008. At the beginning of the credit 

crisis, when credit essentially froze, yields skyrocketed. 

While yields did come down by over a hundred basis points 

in late 2008, they remained elevated above their pre-crisis 

level. Specifically, even though nominal yields declined in 

December, the credit spread (the difference between corporate 

bonds and a 10-year treasury bond) peaked in December 

reaching close to 5 percent for investment grade utilities and 

11.9 percent for noninvestment grade. 

Figure 21

Yields of Utilities, Merchants, and Ten Year 

Treasury Bonds

Source: Derived from Derived from Merrill Lynch Index U.S. Corporates, 

Gas and Electric Utilities and Bloomberg data. 

0

5

10

15

20

Effective Yield (%)

Utilities and merchants, investment

grade

Utilities and merchants, below

investment grade

10-year U.S. Treasury Bond

Calpine 

Bankruptcy 12-05

Enron 

Bankruptcy 

12-01

01 07 01 07 01 07 01 07 01 07 01 07 01 07 01 07 01 07 01

 00 00 01 01 02 02 03 03 04 04 05 05 06 06 07 07 08 08 09

6 U.S. Bureau of Labor Statistics. Avg. Hourly Earnings of Utility Workers: 

CES4422000008 and Avg. Hourly Earnings of Construction Workers: 

CES2000000008. ONLINE. 2009. Available: http://www.bls.gov/data/.

7 Cambridge Energy Research Associates, Capital Costs Analysis Forum – Power: 

North America: Impacts of the Financial Turmoil, March 6, 2009, pages 1, 5-7. 

Verified by staff conversations with various market participants.

8 Edison Electric Institute, The Financial Crisis and Its Impact On the Electric Utility 

Industry, February 2009, pages 10-11 

Bank of America/Merrill Lynch, Wall Street Turmoil: Outlook for 2009 and 

Implications for Utilities and Regulators, February 17, 2009, Slide14. Presented 

at the 2009 NARUC Winter Committee Meetings in Washington, D.C. 
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Potentially due to the increase in yield required to issue 

debt, the tenor of debt in the energy sector moved toward 

shorter term rather than longer term. Figure 22 illustrates 

that borrowing was down in the 3Q08 across all rating 

classifications. In the 4Q08, borrowing for A-rated utilities 

increased, but for shorter tenors. In addition, utilities with 

lower ratings had reduced access to debt markets. According 

to Paul Bowers, Southern Co.’s chief financial office, 

“Some companies with lower credit ratings have not 

been able to access commercial paper or other shortterm credit markets, further exacerbating the impact 

of the credit crunch. In addition to this increased 

cost of debt, the availability and cost of credit from 

banks has been even more severely impacted, due to 

their financial troubles. This is important, since many 

lower-rated utilities rely on banks, rather than capital 

markets, especially for short-term debt financing.”9

 

Figure 22

 Amount of Debt Issued (Utilities)

Source: Derived from Bloomberg data. 

0

2

4

6

8

10

12

14

($) Billions

Over 18 Years

9-17 Years

0-8 Years

A BBB Below BBB

 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 2007 2008 2007 2008 2007 2008

Energy Efficiency

As power plant investments are delayed and costs for 

building new generation remain elevated, demand-side 

resources have become an increasingly integral role in 

managing reserve margins. Most analysts agree that the 

first round of energy efficiency is the least-cost solution. 

The urgency to adopt this least-cost solution is compounded 

because the longer energy efficiency is delayed, the lower 

its potential benefits and higher its potential costs. Building 

energy efficiency into a product initially is much cheaper 

than later retrofitting or replacing the good with a more 

energy efficient good down the road.10 

There are differing estimates of the potential costs and 

benefits of energy efficiency. Assuming energy efficiency is 

not delayed or obstructed, McKinsey & Company estimated 

that energy efficiency has the potential to offset up to 85 

percent of the incremental increase of load by 2030 (see 

Figure 23 on next page), which translates into about 1,292 

TWh. McKinsey’s estimates include the assumption that 

barriers to incorporating energy efficiency are overcome.11

A more conservative estimate by Electric Power Research 

Institute (EPRI) estimated the reduction of load due to energy 

efficiency to be between 398 and 544 TWh, 8.2 percent of 

projected consumption by 2030.12 EPRI also estimated that 

the levelized cost for energy efficiency measures to meet these 

potential reductions by 2030 is 3.22¢ per kWh.13 California 

Energy Commission staff stated that levelized costs for the 

9 Testimony of Paul Bowers, Docket No. AD09-2-000, January 13, 2009, page 4.

10 McKinsey & Company, Reducing U.S. Greenhouse Gas Emissions: How Much at 

What Costs?, December 2007, pages 69-70.

11 Ibid., pages XV, 28-30, 69-70.

12 Assessment of Potential from Energy Efficiency and Demand Response 

Programs in the U.S.: (2010-2030). EPRI, Palo Alto, CA: 2009. 1016987, January 

2009, pages XX.

13 Ibid., pages 6-2.
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energy efficiency programs in all sectors reached a low of a 

little over 1.1¢ per kWh in 2004.14 Thus the cost of achieving 

the level of energy efficiency estimated by EPRI is low when 

compared to the cost of a new typical combined cycle gas 

turbine, which has levelized costs in the range from 7.3 to 

10¢ per kWh.15

Figure 23

Incremental Power Load vs. Potential 

Abatement from Energy Eƥciency and Transportation

1. 2005 load

2. Incremental load

3. 2030 projected load

4. Buildings and applicances

Source: Derived from EIA Energy Outlook (2007) “Reference case;” McKinsey analysis data. 

s

5000

ruo4000 h-tt3000 aw2000 areT1000

0 1 2 3 4 5 6 7

5. Industry 

6. Transportation 

 (plug-in hybrids)

7. 2030 load

40% Net gain from 

energy efficiency 1,520 5,385 1,067

217 4,115 3,865

14

Conclusion

As the summer of 2008 approached, Commission staff 

became concerned that electricity prices for the remainder of 

the summer and possibly far into the future were increasing 

rapidly.16 

In addition, as the cost of key building inputs fell, uncertainty 

permeated credit markets, freezing borrowing and lending. 

As the credit markets started to open, yields skyrocketed 

for those that were able to obtain credit. As investors defer 

building power plants until the costs of doing so falls, 

demand-side resources can become a more integral part of 

the resource adequacy equation. 

14 California Energy Commission Staff Paper, Funding and Savings for Energy 

Efficiency Programs For Program Years 2000 Through 2004, August 2005, 

page 14.

15 Lazard Ltd, Levelized Cost of Energy Analysis - Version 2.0, Presented at the 2008 

NARUC Summer Committee Meetings in Portland Ore., June 2008, http://www.

narucmeetings.org/Presentations/2008 percent20EMP percent20Levelized 

percent20Cost percent20of percent20Energy percent20- percent20Master 

percent20June percent202008 percent20(2).pdf.

16 FERC, Division of Energy Market Oversight. “Increasing Costs in the 

Electric Market.” Federal Energy Regulatory Commission., June 19, 

2008. http://www.ferc.gov/legal/staff-reports/06-19-08-cost-electric.pdf
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Section 4 Physical and Financial 

Bilateral Electricity Trading

During 2008, financial products played a growing 

role in electricity markets. This prominence 

occurred as the volume of physical electricity trading 

continued a multiyear decline, led by reduced 

activity from financial institutions and energy marketers.
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Bilateral Trading 2008 Highlights

In addition to these overarching trends, there were important 

regional differences in electricity trading, to the point that 

one can argue that there were three distinct wholesale 

markets in the United States. In the Northeast and Upper 

Midwest, physical trading took place primarily through 

centralized electricity markets run by regional transmission 

organizations (RTOs). Financial electricity trading ranged 

from moderate to robust in these markets. In the Southeast, 

there was little to no financial electricity trading, and 

physical trading was conducted bilaterally. In the West, the 

only RTO market was California ISO’s real-time market, so 

most physical trading was conducted bilaterally. However, 

in contrast to the Southeast, there was a substantial amount 

of financial electricity trading in the West.

While the volume of financial power traded increased in 

2008 as a whole, there were starkly different trading patterns 

before and after the financial crisis. Financial electricity 

volumes grew substantially relative to 2007 during the first 

seven months of 2008. Financial electricity volumes fell in 

August relative to 2007; by October, uncertainties in financial 

markets contributed to decreased financial power trading, as 

the last three months in 2008 all traded below 2007 levels. 

The volume of longer-term financial electricity products fell 

significantly during the fourth quarter, likely because credit 

tightening made it more difficult to meet credit requirements 

necessary for longer term deals. 

Bilateral Trading Mechanics 

and Reporting

Physical buyers and sellers can transact in a number of ways. 

Buyers and sellers use bilateral phone calls or instant messages, 

voice-broker services and electronic platforms, among other 

means, to find counterparties. Regardless of the manner by 

which buyers and sellers transact business, Commissionjurisdictional sellers must report sales transactions to the 

Commission through the Electric Quarterly Report (EQR). 

Sales by public power entities and federal power agencies 

such as Bonneville Power Administration are not reported to 

the Commission.

Financial buyers and sellers can also transact in a number of 

ways, including using voice brokers and electronic platforms 

such as the IntercontinentalExchange (ICE). Financial 

power transacted on ICE is typically traded as a financial 

swap, meaning that a buyer pays a fixed price for power 

and receives not power, but a floating price determined 

by a specific index. This index is commonly derived from 

physical electricity market outcomes, e.g., RTO market results 

(day-ahead or real-time LMP averages) or next-day physical 

delivery prices reported to index developers. 

Buyers and sellers of financial electricity products are 

not required to report transaction-level data or aggregate 

holdings to the Commission, though Commission staff can 

obtain information about open interest in the financial 

contracts traded on ICE. As a result, we can report on trends 

in the types and quantity of financial products traded, but 

we are unable to address trading trends by individual market 

participants or participant class.1

1 While financial electricity trading occurs off the ICE trading platform and EQR 

volumes do not include physical sales by entities that are not jurisdictional 

to FERC, we nonetheless believe comparisons based on ICE and EQR volumes 

provide important insights into underlying patterns.
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Continued Wholesale Power Declines

The volume of physical electricity sales reported in the 

EQR has declined consistently over the past four years. 

Specifically, physical wholesale power volumes have fallen 

every quarter, relative to the previous year, since 4Q04, 

excluding 1Q08. In 2008, EQR reported volumes declined 

9 percent from 2007 levels, after having fallen 13 percent 

in 2007 and 6 percent in 2006. This decline occurred across 

the United States, but relatively more in California, New 

England and ReliablilityFirst NERC subregions (see Table 

1). Changes in sales volumes in those NERC subregions that 

did show growth (Florida Reliability Coordinating Council, 

Gateway and Rocky Mountain Power Area) can be attributed 

to individual company behavior changes and do not appear 

to represent systemic increases in activity.2

Exit of Financial Institutions, Marketers 

Drives EQR Volumes Down

Focusing on the types of entities selling power can provide 

clues into understanding why physical wholesale power 

volumes are decreasing. After classifying entities that 

report wholesale power sales to EQR into three different 

classifications (financial/marketer (F/M), independent power 

producer (IPP) and utility),3 one can clearly see that reduced 

activity by financial/marketing companies has driven the 

decline in EQR-reported sales (see Figure 1, next page). 

Specifically, decreases in wholesale power sales by financial/

marketing companies has accounted for 78% of total EQRreported sales declines since 2005, when the decline in EQRreported sales started. 

Table 1 EQR Reported Sales by NERC Sub Region in TWh (2008 vs. 2007)

NERC Sub Region 2008 2007 ∆ (TWh) % Growth

-5%

-25%

-3%

-9%

-17%

-24%

84%

62%

2%

0%

6%

-9%

-25%

-1%

39%

Eastern RTOs Midwest Reliability Organization 222 233 -11

New England 351 468 -116

New York 177 183 -6

ReliabilityFirst 1578 1727 -148

Southeast States Central (TVA) 15 18 -3

Delta (Entergy) 92 121 -30

Florida Reliability Coordinating Council 30 16 13

Gateway 223 138 86

Southeastern (Southern) 125 123 3

Southwest Power Pool 69 69 0

Virginia Carolinas Reliability Agreement 34 32 2

Western States Arizona / New Mexico / Southern Nevada 194 214 -20

California 520 692 -172

Northwest Powerpool 321 325 -4

Rocky Mountain Power Area 22

Source: Derived from Electric Quarterly Report data.

16 6

3 Business sector classifications from Ventyx. Financial/marketer (F/M) 2 In FRCC, Southern Company reported 1.55 TWh in electricity sales during 2007 

indicates physical electricity player with no generation assets, independent through EQR and 13.11 TWh in 2008. In Gateway, Ameren reported 100.95 power producer (IPP) is a nonutility generator and utility is a utility generator. TWh in 2007 and 188.54 TWh in 2008. In RMPA, Black Hills Corp reported 1.38 Business sector classifications are applied to the reported seller, not the TWh in 2007 and 2.77 TWh in 2008 while Calpine Corp. reported 1.36 TWh in 

holding company level. 2007 and 4.52 TWh in 2008.
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Figure 24

EQR Decline led by Financial Markets Sellers

Source: Derived from from Electric Quarterly Report data. 

0

500

 1000

 1500

 2000

 2500

 3000

 3500

2005 2006 2007 2008

TWh

F/M

IPP

Utility

The reduction in physical sales by financial/marketer 

companies has been particularly noticeable in the 

ReliabilityFirst, New England and California NERC subregions 

(see Table 2). These are areas with either well-established 

centralized wholesale electricity markets (ReliabilityFirst, 

New England) or robust financial electricity markets 

(ReliabilityFirst, California). Therefore, it appears that traders 

that do not own physical generation are gravitating away 

from physical sales and to financial electricity trading. In 

parts of the Southeast, notably the Southeastern (Southern) 

NERC subregion, financial/marketer companies increased 

power wholesales in 2008 by over 60 percent since 2005; 

this was driven largely by Constellation’s increased activity 

in the Southeast.

Table 2 

Physical Electricy Sales by Financial Institutions and Energy Marketers by NERC Subregion in TWh (2008 vs. 2005)

NERC Subregion 2008 2005 ∆ (TWh) % Growth

-24%

-54%

44%

-54%

67%

9%

7%

4%

62%

-34%

116%

3%

-41%

12%

195%

Eastern RTOs Midwest Reliability Organization 90 118 -28

New England 196 423 -227

New York 79 55 24

ReliabilityFirst 590 1,283 -693

Southeast States Central (TVA) 9 5 4

Delta (Entergy) 40 37 3

Florida Reliability Coordinating Council 4 3 0

Gateway 35 33 1

Southeastern (Southern) 73 45 28

Southwest Power Pool 10 16 -5

Virginia Carolinas Reliability Agreement 17 8 9

Western States Arizona / New Mexico / Southern Nevada 135 131 4

California 404 682 -278

Northwest Powerpool 221 198 23

Source: Derive

Rocky Mountain Power Area

d from Electric Quarterly Report data

 2 1 1
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Regional Characteristics of Wholesale 

Power Trading

A review of physical and financial trading suggests that there 

are three distinct wholesale markets in the United States (see 

Figure 25). In the Northeast and Upper Midwest, physical 

trading takes place primarily through centralized electricity 

markets run by regional transmission organizations (RTOs) 

with Day-2 markets.4 Financial electricity trading ranges 

from moderate to robust in these markets. In the Southeast, 

there is little to no financial electricity trading, and physical 

trading is conducted bilaterally. In the West, the only RTO 

market was California ISO’s real-time market, so most 

physical trading was conducted bilaterally. However, in 

contrast to the Southeast, there was a substantial amount of 

financial electricity trading in the West.

Figure 25

Majority of Sales in Eastern RTO 

areas to the RTO

Source: Derived from Electric Quarterly Report and IntercontinentalExchange data. 

0

200

400

600

800

1000

1200

1400

1600

1800

MRO NPCC RFC WECC FRCC SERC SPP

TWh

ICE Fin Swaps

Non-RTO Sales (Not Affiliated)

RTO Sales

Eastern RTOs Western States Southeast States

Eastern RTOs 

In the region that comprises the eastern RTOs, the majority of 

EQR-reported wholesale power sales are into the RTO markets. 

Figure 25 shows this relationship well, as ReliabilityFirst 

(RFC), Northeast Power Coordination Council (NPCC) and 

Midwest Reliability Organization (MRO) NERC regions form 

a close geographic proxy to eastern RTOs. About 60 percent 

of sales (excluding sales to affiliates) were made into the RTO 

markets. Sales to affiliated entities are often characterized 

by generation arms of a company handing electricity to 

retail arms to serve load or marketing arms for resale; as a 

result we discount sales to affiliates to some degree.5 

No category of entity dominates physical trading in the 

eastern RTOs (see Figure 25). In RFC, financial marketers, 

IPPs and utilities each made about a third of the physical 

sales reported to EQR. In MRO, on the other hand, IPPs 

played a small role in the physical market, having made 

around 16 percent of all sales reported to EQR, while utilities 

made 46 percent of physical sales. In contrast, utilities made 

relatively few sales in NPCC, with less than 13 percent of the 

physical sales volume. Financial marketers were the largest 

seller group in NPCC, with 61 percent of the sales. 

The variation across regions was driven in part by the degree 

to which the states in the region restructured and have retail 

choice. For instance, all of the states in NPCC except for 

4 “Day-2 markets” refers to those RTOs with both day-ahead and real-time 

electricity markets. In 2008, this included ISO-NE, MISO, NYISO and PJM. In 

2008, neither CAISO nor SPP administered a day-ahead energy market.

5 Mirant’s wholesale power activities in PJM provide a good example of 

an affiliated sale. Specifically, in 3Q08, Mirant’s generation assets in PJM 

produced a reported 4.29 TWh of electricity sales in the EQR. That entire 4.29 

TWh was then sold to Mirant’s marketing arm, Mirant Energy Trading LLC, 

which sold the same amount of energy to PJM. If one added up Mirant’s 

entire 3Q08 sales in PJM, the total would be 8.58 TWh. This number is twice 

the amount of electricity generated by Mirant in PJM during 3Q08, indicating 

the necessity to discount sales to affiliated entities in this case. CEMS data 

confirms that Mirant sold its entire output at Chalk Point, Morgantown, 

Potamac River and Dickerson into wholesale markets.
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Vermont have restructured and offer retail choice.6 On the 

other hand, none of the states in MRO have restructured. 

RFC is a mixed bag, with Delaware, Illinois, Michigan, 

Maryland, New Jersey, Ohio and Pennsylvania restructured 

and Indiana, Kentucky and West Virginia still traditionally 

organized. 

Figure 26

WECC Power Sales Dominated 

by Financial/Marketers

Source: Derived from Electric Quarterly Report and IntercontinentalExchange data. 

0

200

400

600

800

 1000

 1200

 1400

 1600

 1800

MRO NPCC RFC WECC FRCC SERC SPP

TWh

ICE Fin Swaps

EQR Utility Sales

EQR IPP Sales

EQR F/M Sales

Eastern RTOs Western States Southeast States

There is some variation in the level of financial electricity 

trading across the eastern RTOs. In RFC, the volume of 

financial electricity traded on ICE surpassed the level of 

physical sales of electricity. In NPCC (roughly NYISO and 

ISO-NE), financial electricity volumes were about 76 percent 

of the volume of physical trading. In MRO, there was little 

financial trading. These differences are partially attributable 

to the maturity of the RTO markets in each region, with the 

Midwest ISO (located in MRO) being the youngest Day-2 

RTO market.

Western States

Physical sales in western states (here represented by the 

Western Electricity Coordination Council (WECC) NERC 

region) were almost entirely bilateral sales, with a small 

amount sold into the California ISO’s real-time market. The 

volume of financial sales on ICE was roughly as large as 

physical sales. ICE lists financial electricity products at a 

number of locations in the West, including SP-15, MidColumbia, Palo Verde and NP-15, along with a number of 

other smaller-volume locations. 

Physical sales in WECC were dominated by financial/

marketing companies. During 2008, 72 percent of total 

wholesale power was sold by financial/marketing companies, 

well above other regions (see Figure 26). This pattern remains 

consistent across all NERC subregions in WECC7

, except in 

Rocky Mountain Power Area (RMPA), which accounted for 

less than 2 percent of WECC sales in 2008. Trading in the 

western states differs from the rest of the country as financial 

players are very active in the physical markets, despite the 

fact that there is a robust financial electricity market. One 

possible explanation is that financial players and energy 

marketers are providing the trade coordination role provided 

by eastern RTOs. That said, physical sales reported through 

EQR in the three largest western pricing hubs (SP-15, MidColumbia and Palo Verde) continued a multiyear decline, as 

discussed above. These pricing zones are also the largest 

financial electricity markets in the West. Some smaller 

pricing hubs with relatively little financial trading activity, 

(NP-15, California-Oregon border and Mead) had modestly 

higher physical volumes in 2008.

Barclays’s electricity sales and purchases during 3Q08 provide 

a good example of financial institution/marketer activities. 

Barclays was the third-largest electricity wholesaler even 

6 Energy Information Administration, Electric Restructuring by State, http://

www.eia.doe.gov/cneaf/electricity/page/restructuring/restructure_elect.html 7 California (CA), Arizona/New Mexico/Southern Nevada (AZNMSNV) and 

Northwest Powerpool (NWPP)
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though it owns no electricity generation assets.8 Notably, 

the top five companies Barclays purchased electricity from 

and sold electricity to were all also financial/marketer 

companies.9 Specifically, 71 percent of Barclays electricity 

purchases were from five financial/marketer companies;10

while 69 percent of Barclay PLC’s energy sales were to five 

financial marketer companies.11

Southeast States

Virtually all the physical sales in the Southeast were 

consummated bilaterally. The NERC regions Florida 

Reliability Coordinating Council (FRCC), Southeastern 

Electric Reliability Council (SERC) and Southwest Power Pool 

(SPP) provide an approximate geographical proxy for this 

area. Sales reported in the EQR during 2008 were dominated 

by IPPs and traditional utility sellers, with some important 

differences within the region (see Figure 26). In both FRCC 

and SPP, financial/marketer sales accounted for less than 15 

percent of total wholesale power transactions in 2008.

In contrast, sales by financial/marketer sellers in SERC 

accounted for 35 percent of total sales. In addition, financial 

institutions and marketers had an even larger presence 

in some areas within SERC. For instance, the financial/

marketer presence in the Southeast (SOCO) was particularly 

high (over 57 percent of total sales). The large presence 

of financial/marketer in SOCO was driven by Constellation 

Energy Commodities Group’s activities, which was the largest 

financial/marketer seller in SOCO with 41 percent of total 

financial/marketer sales. While Constellation does not own 

generation in SOCO, it does have several multiyear tolling 

agreements with generating units in the region.

Interest in financial power products in the Southeast is weak, 

as ICE does not currently provide a financial-swap product 

in FRCC, SERC or SPP.

Growing Prominence of Financial 

Electricity Products

Financial power volumes traded on ICE have grown each 

year since at least 2005, while physical power volumes 

traded as reported in EQR have declined each year since 

2005 (Figure 27). 

Figure 27

Wholesale Power Declines Coincide 

with Increased Interest in Derivatives

Source: Derived from from Electric Quarterly Report and IntercontinentalExchange data. 

2005 2006 2007 2008 2005 2006 2007 2008

0

1

2

3

4

5

6

ICE Financial Power EQR Reported Sales

GWh (Thousands)

During 2008, financial power volumes traded on ICE grew 

21 percent, surpassing 3,050 TWh. Yearly trading volume 

records were set at nearly every trading hub, including PJM 

West, Mid-Columbia, NP-15, SP-15, NYISO Zone G, Nepool 

and Palo Verde. Increases at western hubs alone accounted 

8 Neither Barclays PLC nor any of its subsidiaries owns electricity generation 

assets ,according to Bloomberg data.

9 All figures based only on transactions reported to EQR.

10 Morgan Stanley (33 percent), RBS (23 percent), Goldman Sachs (7 percent), 

Citigroup (6 percent) and JP Morgan Chase (includes BearEnergy) (3 percent)

11 Morgan Stanley (37 percent), RBS (17 percent), Goldman Sachs (6 percent), 

Royal Dutch Shell (includes Coral Power LLC ) (5 percent) and Citigroup (4 

percent)
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for more than 75 percent of the growth in financial power 

on ICE. This growth was most noticeable at SP-15 and MidColumbia, the second- and third-most actively traded hubs 

on ICE. 

While financial power traded on ICE increased 21 percent in 

2008, it is misleading to look at 2008 in aggregate. Instead, 

it is important to separate increases through July from later 

financial crisis-related decreases.

The Rise

Financial power began the year with spectacular gains in 

volume relative to 2007. Volumes during the first seven 

months were 48 percent higher than the same months in 

2007 (see Figure 28). Volumes in February and April alone 

were 80 percent higher than 2007 levels. This rate of growth 

sets the standard against which to measure the remainder of 

the year.

Figure 28

Strong ICE Financial Power Gains 

Followed by Contraction

Source: Derived from IntercontinentalExchange data. 

0

100

200

300

400

J FMAMJ J ASOND

GWh (Thousands)

2007 2008

47% 81% 63%

79%

38% 21% 30%

-7% 12% -13%-41%

-29%

The Fall

Significant downturns in financial trading volume first 

appeared at the most actively traded hub, PJM West (52 

percent of total financial power on ICE) in August. Rebounds 

in September trading, the same month Lehman Brothers 

filed for bankruptcy and Bank of America agreed to acquire 

Merrell Lynch, could stem from companies unwinding 

or closing financial power positions. In addition, the 12- 

percent increase in volume must be compared to much 

higher growth rates in the first seven months. By October, 

uncertainties in financial markets contributed to decreased 

financial power trading, as the last three months in 2008 all 

traded below 2007 levels. Several hubs did well during the 

economic malaise; 4Q08 volumes at NP-15 and Palo Verde 

were substantially higher than 4Q07 levels. In the end, 

however, ICE financial power trading during 4Q08 was the 

lowest fourth quarter traded on ICE since 2005.

Notably, the volume of physical wholesale power trading did 

not appear to respond to credit tightening as was seen in 

financial power markets. Specifically, the 2008 decrease in 

third- and fourth-quarter physical sales on a year-to-year 

basis were not substantially different that the 2007 year-toyear declines in those same months.12 

12 Physical volumes during 3Q08 declined by 13 percent relative to 3Q07, while 

3Q07 declined by 16 percent relative to 3Q06. Similarly, 4Q08 volumes declined 

16 percent relative to 4Q07, while 4Q07 declined 11 percent relative to 4Q06.
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Table 3

Financial Electricity Trading on ICE in the 4th 

Quarter by Term (2008 vs. 2007)

2008Q4 2007Q4 ∆ (TWh) % Growth

Calendar Year Terms 38 84 -46 -55%

Quarterly Terms 70 74 -4 -6%

Montly Terms 275 399 -124 -31%

Spot (<1 month) 77 76 1 2%

Total 460 633 -173 -27%

Source: Derived from IntercontinentalExchange data.

Changes in the Term Structure for 

Financial and Physical Power

Financial Products

Financial power trading on ICE is used mostly for term 

transactions (see Figure 29). In 2008, 88 percent of total 

volumes were term (65 percent monthly, 15 percent quarterly, 

8 percent calendar year) while only 12 percent were spot 

(less than one month). 

Changes in trade length were particularly apparent during 

4Q08 as credit tightening may have made it more difficult 

to meet credit requirements necessary for longer term deals. 

For instance, although total volume traded during 4Q08 

decreased 27 percent relative to 4Q07, spot deals increased 

2 percent (see Table 3). During the same time, monthly and 

calendar year deals decreased faster than total financial 

power declines, while quarterly volumes declined at a slower 

rate. Calendar year trading, especially at PJM West and SP15, dried up during 4Q08, when volumes fell by 69 percent 

and 52 percent, respectively, compared to 4Q07, despite total 

financial power volumes falling by smaller amounts at both 

hubs, 54 percent and 10 percent, respectively.

Figure 29

Financial Power Sales on ICE Outpaced Physical

Source: Derived from IntercontinentalExchange data. 

0

0.5

1

1.5

2

2.5

3

3.5

04 05 06 07 08

GWh (Thousands)

Spot (< 1 Month)

Monthly

Quarterly

Calendar Year

04 05 06 07 08

0

100

200

300

400

04 05 06 07 08

GWh (Thousands)

ICE Financial Power Volumes ICE Physical Power Volumes

Physical Products

The volume of physical long-term (a year or more) sales 

transactions rose significantly between 2007 and 2008. 

Long-term sales volumes accounted for 43 percent of all 

EQR sales in 2008, up from 33 percent in 2007. Regionally, 

SPP, the Southeast and ERCOT had the highest percentages 

of long-term sales transaction in 2008. With the exception 

of ERCOT, these are areas where there are no RTO markets. 

The Northeast and the West had the lowest percentage of 

long-term sales. These are areas that have relatively robust 

financial electricity markets. 
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Table 4 EQR Transaction Volumes

2007 2008

Short Term Long Term Total Short Term Long Term Total

 GWh % GWh % GWh % GWh % 

Northeast 534,706 78% 149,126 22% 683,833 407,519 73% 148,102 27% 555,622 

Mid-Atlantic/ Midwest 1,301,306 61% 846,210 39% 2,147,516 1,108,131 52% 1,018,065 48% 2,126,196 

Southeast 153,929 53% 134,254 47% 288,183 137,039 44% 175,995 56% 313,034 

ERCOT 123,953 67% 61,876 33% 185,829 105,824 51% 103,726 49% 209,550 

SPP 31,243 47% 35,151 53% 66,394 32,061 41% 45,216 59% 77,277 

West 910,494 75% 308,859 25% 1,219,353 722,273 65% 381,724 35% 1,103,997 

Total 3,055,630 67% 1,535,477 33% 4,591,107 2,512,847 57% 1,872,828 43% 4,385,675 

Power sales transactions with durations of one year or greater are long-term. 

Transactions with shorter durations are short-term. 

Source: Derived from Electric Quarterly Report data.
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Section 5 RTO/ISO Capacity Markets

During 2008, energy efficiency and demandresponse resources played an important role 

in several RTO capacity markets.
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Introduction

In 2008, Commission-approved capacity markets operated 

in three RTO/ISOs. These include ISO-NE’s forward capacity 

market (FCM), PJM’s reliability pricing model (RPM) and 

NYISO’s installed capacity market (ICAP). In general, the 

goal of each capacity market is to provide a means for 

load-serving entities (LSE) to procure capacity needed to 

meet forecast load, or resource adequacy, requirements 

and to allow generators to recover a portion of their fixed 

costs.1 The ISO-NE’s FCM and PJM’s RPM employ forward 

commitment auctions for capacity. That is, supplies awarded 

in the auction represent commitments to provide capacity 

three years in the future. The auctions are intended to create 

a smoother, more stable price signal to suppliers considering 

investment decisions. The NYISO’s ICAP auctions provide 

semiannual seasonal strip auctions. In NYISO, suppliers 

are not assured of the amount of payments for providing 

capacity in forward years, as in PJM and ISO-NE. 

Capacity Markets in Action in 2008 

The three RTO/ISOs conducted six capability or delivery-year 

auctions in 2008.2 There were two base auctions each in ISONE, PJM and NYISO, not including the various incremental 

or reconfiguration auctions that cover shorter periods. 

ISO-NE and PJM held their first auctions with a three-year 

forward commitment in 2008.3 In NYISO’s ICAP market, 

capability auctions were held for summer 2008 and winter 

2008-09 (monthly and spot capacity auctions were also 

held). 

Overall, the auctions attracted new investment. In ISO-NE 

and PJM, a combined total of approximately 8,900 MW of 

new generation and demand response was committed for 

the forward delivery periods of 2010-11 and 2011-12. This 

compares to 2008 overall generation capacity figures of 

31,100 MW in ISO-NE and 164,895 MW in PJM. In 2008, 

NYISO saw an increase of 1,075 MW of new generation, 

net of retirements, relative to approximately 38,900 MW of 

overall generation capacity in the market. Total capacity 

offered and purchased in New York exceeded the state’s 

minimum resource adequacy requirements in 2008.

As discussed below, prices for the forward capacity markets 

of ISO-NE and PJM were generally in the $40 to $60/kWyear range for the capability or delivery year auctions 

conducted in 2008. Prices in NYISO’s 2008 auctions ranged 

from $78/kW-year ($6.50/kW-month) for New York City 

in the summer period to $21/kW-year ($1.77/kW-month) 

for the non-New York City and non-Long Island area (also 

referred to as rest-of-state) in the winter period. Capacity 

prices declined going from the first capability or delivery 

year auction to the second, for each of the three markets. 

1 The demand for each market is based on the following, listed by market. 

In ISO-NE FCM, an installed capacity requirement (ICR) is calculated based 

on load forecast, unit availability and intertie benefits. In PJM, RPM uses a 

downward-sloping demand curve based on target reserve margins. In NYISO, 

a downward-sloping demand curve is based on the installed reserve margins 

for New York – Rest of State, Locational Minimum ICRs for NYC and Long 

Island.

2 The capacity auctions cover periods up to one year. In ISO-NE, a capability 

year under the FCM is from June 1 through May 31, three years forward. Under 

PJM’s base residual auctions, capacity commitments are for a delivery year 

from June 1 through May 31, three years forward. In NYISO, capability periods 

are six-month periods established as a summer capability period, May 1 

through Oct. 31, and a winter capability period from November 1 of each year 

through April 30 of the following year. Each market also conducts shorterduration auctions – e.g., reconfiguration, monthly or spot auctions – in which 

market participants can purchase capacity for incremental load growth or 

supply deficiencies. Discussion in this report focuses mainly on capability and 

delivery-year auction results.

3 ISO-NE conducted the first FCM auction in February 2008, which secured 

resource commitments for the 2010-11 timeframe, and the second FCM 

auction in December 2008, securing 2011-12 resource commitments. PJM held 

its 2010-11 RPM auction in January 2008 and its 2011-12 RPM auction in May 

2008.
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Table 5: Comparison of Capacity Markets in RTO/ISOs

Capacity Market ISO-NE – Forward Capacity Market PJM – Reliability Pricing Model NYISO – Capacity Market

Delivery year for base 

auction 

 

Forward procurement: 

Resources are committed 

3 years into the future 

Forward procurement: 

Resources are committed 

3 years into the future 

Six-month strips: 

Resources are committed for the 

coming season, winter and summer

Price determination Descending clock auction 

 

Price determined in auction by 

intersection	of	supply	offers	with	

a calculated demand curve _1/ 

Price determined in auction by 

intersection	of	supply	offers	with	

a calculated demand curve _2/

Demand basis 

 (i.e., demand based on...) 

 

An Installed Capacity Requirement 

(ICR) is calculated based on 

forecast and other parameters _3/ 

Downward sloping demand curve 

based on net cost of new entry 

and target reserve margins 

Downward sloping demand curve, 

installed reserve margins for state; 

locational minimum ICR for 

NYC, Long Island _4/

Self-supply option or 

must-bid? 

LSEs may self-supply LSEs are able to self-supply or 

mandatory participation by 

load except for FRR option 

LSEs self-supply, or utilize ICAP 

auctions and/or bilateral 

arrangements _5/

Must-offer?	 Must-offer	requirement	for	capacity	 Must-offer	

capacity 

requirement	for	 Must-offer	requirement	

for NYC only

for	capacity	

Locational requirements 

and pricing

Yes _7/ Yes _6/ Yes _8/ 

Market	power	mitigation	 Review	of	bids	priced	above	and	

below	specified	thresholds	_9/	

Offer	caps	based	

cost	of	capacity	

on	marginal	 Offer	caps	for	certain	capacity	in	NYC

spot	market	auctions	_10/	Penalties

for	failure	to	offer	certain	capacity	in

NYC _11/ Audits for proposals to 

delist	_12/	Offer	Floor	for	NYC	Spot	

Market Auctions _13/

Demand	Resources	(DR)		

and other nongeneration 

resources 

DR	and	energy	efficiency	projects	

may participate in the auction 

Capacity	may	be	provided	from	

demand response resources and 

new transmission projects 

DR	may	participate	

auctions 

in	all	NYISO	ICAP

Auction	frequency	 Annual	Reconfiguration	auctions	

performed annually, seasonally 

and monthly _14/ 

Annual	Incremental	auctions	may	

be held prior to the delivery year 

Capability	period	auction	(covers	

month period) monthly auction, 

spot market auction

a	six-

_1/ PJM’s demand curves, referred to as variable resource requirement (VRR) curves, are administratively determined.

_2/ Three ICAP demand curves are used in the ICAP spot market auction: one each to determine the locational component of LSE UCAP obligations for Long Island and for New 

York City, and the third to determine the total LSE UCAP obligations for all LSEs.

_3/ ISO-NE’s installed capacity requirement (ICR) is based on three components (load forecast, unit availability and tie benefits) and is the amount of resources needed to 

meet the planning reliability requirements defined for the New England Control Area such that the probability of disconnecting noninterruptible customers (a loss of load 

expectation) is no more than once every 10(ISO-NE Market Rule 1 § III.12). 

_4/ Once ICAP is determined, the NYISO converts the requirements into unforced capacity (UCAP).

_5/ Participation in NYISO auctions is restricted to NYISO customers – i.e., entities that have signed NYISO service agreements for market services and control area services.

_6/ Locational requirements are defined by transmission constraints.

_7/ Capacity zones are determined before the FCA based on an identification of transmission limits that may bind in the FCA.

_8/ Three ICAP demand curves are used in the ICAP spot market auction: one each to determine the locational component of LSE UCAP obligations for Long Island and for New 

York City, and the third to determine the total LSE UCAP obligations for all LSEs.

_9/ See ISO-NE Market Rule I, §§ III.13.1.1 through III.13.1.3, and III.13.1.7.

_10/ Offer caps in New York City are based on reference levels or avoided costs. Mitigated UCAP must be offered in each ICAP spot market auction, unless it has been exported 

to an external control area or sold to meet installed capacity requirements outside New York City in a transaction that does not constitute physical withholding.

_11/ Exports of mitigated UCAP are considered to have been physically withheld from the New York City market if: (1) the net revenues from the sale of the exported UCAP in 

New York City would have been greater by 5% or more than the net UCAP revenues from the export sale; and (2) the exporting market participant could have made all or 

a portion of the exported UCAP available to be offered in New York City by buying out of its external capacity obligation through participation in an external reconfiguration 

market.

_12/ Any proposal or decision by a market participant to retire or otherwise remove a supplier from the mitigated UCAP market, or to de-rate the amount of installed capacity 

available from such supplier, may be subject to audit and review by the NYISO, if the ISO determines that such action could reasonably be expected to affect marketclearing prices in one or more ICAP spot market auctions for New York City, to determine whether the proposal or decision has a legitimate economic justification or is 

based on an effort to physically withhold installed capacity in order to affect prices. 

_13/ Unless exempt, offers to supply UCAP in an ICAP spot market auction from a New York City installed capacity supplier or demand response resource must equal or exceed an applicable offer floor. A New York City installed capacity supplier that is not a demand response supplier is exempt from an offer floor if it was an existing facility 

on or before March 7, 2008. All other exemptions are based on certain calculations tied to the relationship of the net cost of new entry to projected auction prices. 

_14/ Reconfiguration auctions, conducted after the primary auction, enable trading of obligations and adjustments to capacity purchases. See ISO-NE Market Rule 1, § III.13.4.
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ISO-NE and PJM increased the role of demand resources, 

which competed alongside traditional generating resources 

to meet future load growth. ISO-NE cleared 1,188 MW of 

new demand-response and energy-efficiency resources 

in its first forward 2008 capacity auction and 448 MW of 

new demand response and energy-efficiency resources in 

its second auction. PJM cleared 29 MW of new demandresponse in its first forward auction and 662 MW of new 

demand-response in its second auction.

The following sections describe the capacity markets in ISONE, PJM and NYISO, along with the fundamental factors 

influencing the markets in 2008. Table 5 on the previous 

page shows a comparison of the key features of the three 

capacity markets.

ISO-NE’s Forward Capacity Market 

In ISO-NE’s annual forward capacity auctions (FCA), both 

generator and demand resources offer capacity three years 

in advance of the period for which capacity will be supplied. 

Resources whose capacity clears the FCA acquire capacity 

supply obligations.4 ISO-NE held the first two FCAs in 2008 

for the 2010-11 and 2011-12 delivery years.5 The first full 

year of capacity market commitments begin June 1, 2010. 

Capacity is paid a flat rate for a transition period (Dec. 1, 

2006, through May 31, 2010) prior to ISO-NE’s full, threeyear forward FCA auction mechanism.6

 The FCA process 

includes the modeling of certain constraints to determine if 

load zones will be import- or export-constrained. LSEs that 

designate self-supply resources must offer those resources 

into the FCA and will have the same rights and obligations 

as other capacity resources accepted in the FCA.

Use of New Demand Response and Energy 

Efficiency to Meet Load Forecast

Capacity projections manifest in ISO-NE’s FCM auction 

results showed that market participants were willing to 

commit new capacity resources despite prices at or near 

minimum levels included in the market rules. FCM prices 

cleared at the market’s floor price in both auctions held in 

2008, as described below.

A total of 34,353 MW of existing and new resources cleared 

the auction for the 2010-11 delivery year. New resources 

totaled 1,814 MW, which included 626 MW of new generation 

capacity and 1,188 MW of new demand resources. A total 

of 37,442 MW of existing and new resources cleared the 

auction for the 2011-12 delivery year. New resources totaled 

3,134 MW, which included 1,157 MW of new generation 

capacity, 1,529 MW of new imports and 448 MW of new 

demand resources.

With offered capacity quantities greater than the ISO-NE’s 

installed capacity requirement (ICR), ISO-NE saw downward 

pressure on prices. ISO-NE’s FCM clearing price reached the 

administratively determined floor price of $54/kW-year in 

the 2010-11 auction. ISO-NE’s FCM auction also cleared at 

the (lower) floor price of $43/kW-year for 2011-12. Offers 

4 The Commission approved a settlement agreement in 2006 which provided 

a framework for drafting ISO-NE’s FCM rules. Devon Power LLC, 115 FERC ¶ 

61,340 (2006), order on reh’g, 117 FERC ¶ 61,333 (2006). The Commission 

approved the FCM rules in 2007. ISO New England Inc., 119 FERC ¶ 61,045 

(2007), order on reh’g, 120 FERC ¶ 61,087 (2007) and ISO New England Inc., 

119 FERC ¶ 61,239 (2007). Prior to the delivery year, parties can adjust their 

capacity supply obligations, and ISO-NE can increase or decrease the amount 

of capacity it anticipates needing, in periodic reconfiguration auctions.

5 Beginning in 1998, ISO-NE operated a bid-based market for installed capacity. 

See Devon Power LLC, 115 FERC ¶ 61,340 (2006) at page 5.

6 Devon Power LLC, 115 FERC ¶ 61,340 (2006), page 30. The level of payments 

during the transition period were as follows: Dec. 1, 2006 – May 31, 2007, was 

$3.05/kW-month; June 1, 2007 – May 31, 2008, was $3.05/kW-month; June 1, 

2008 – May 31, 2009, was $3.75/kW-month; and June 1, 2009 – May 31, 2010, 

was $4.10/kW-month.
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for new generation, increased demand response and new 

energy efficiency bolstered supplies for the 2011-12 delivery 

year. Bilateral contracting provided another avenue for 

capacity to receive revenues. For example, in Connecticut, 

678 MW of new generation was committed as a result of 

state requirements for utility procurements.7

For both auctions, ISO-NE modeled two import- or exportconstrained capacity zones in the FCA, Maine and Rest of 

Pool.8 There was no distinct capacity clearing price in the 

Maine capacity zone. Therefore, the auctions resulted in a 

single capacity zone encompassing the entire region without 

price splits or separations by zone.

PJM’s Reliability Pricing Model

Annual RPM capacity market auctions, referred to as base 

residual auctions (BRA), are based on a three-year forward 

obligation to provide capacity. Supply offers are cleared 

against a downward-sloping demand curve, called the 

variable resource requirement (VRR) curve.9 The VRR curve 

establishes the amount of capacity that PJM requires its LSEs 

to purchase and, in conjunction with the capacity offers, 

the price for that capacity. LSEs that are able to fully supply 

their own capacity needs can choose not to participate in 

the RPM auctions, and instead choose a long-term fixed 

resource requirement option.10 

Figure 30 

ISO-NE Quantity of New Resources Cleared 

in Forward Capacity Auctions Held in 2008

Source: Derived from ISO-NE data. 

0

1000

2000

3000

4000

 2010/2011 2011/2012

Capacity (MW)

New demand

resources

New generation

New imports

ISO-NE Clearing Price For Resources Cleared 

in Forward Capacity Auctions Held in 2008

Source: Derived from ISO-NE data. 

0

20

40

60

2010/2011 2011/2012

($ per kW-year)

Figure 31 

7 On June 25, the Connecticut Department of Public Utility Control (DPUC) 

issued a final order selecting three natural gas peaking generation projects 

totaling 678 MW to be constructed in the state (Docket No. 08-01-01, initiated 

in accordance with House Bill 7432, enacted in 2007). State law required 

electric distribution companies to submit plans to the DPUC in 2008 to build 

peaking generation units. In a Dec. 4, 2007, decision related to the new law, 

the department identified a need for 500-700 MW of new peaking generation. 

The DPUC determined that the selected units are to be subject to annual rate 

cases (cost-of-service regulation). As required by the law, the DPUC is to set 

the initial prices for the facilities as they are put in service, and will review 

the cost-of-service of the selected units in annual rate cases and update the 

project’s ROE at least every four years (Connecticut DPUC selects peaking 

generation projects, SNL Energy, June 26, 2008).

8 The Rest of Pool Capacity Zone included Massachusetts, Connecticut, Rhode 

Island, New Hampshire and Vermont. 

9 The VRR curve is based on the target level of reserves and the cost of new 

entry minus an offset for energy and ancillary services revenues. See PJM 

tariff, Attachment DD § 5.10.

10 The FRR alternative permits LSEs to opt out of RPM auctions and instead 

meet a fixed capacity obligation through their own generation or contracts 

sufficient to meet PJM’s reserve margin. 
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PJM held two BRAs in 2008: in January for the 2010-11 

delivery year and in May for the 2011-12 delivery year. The 

auction for the 2011-12 delivery year was the first to procure 

capacity under a full three-year forward commitment. Since 

2007, PJM has conducted a series of transitional auctions to 

cover the capacity market from 2007 through May 2010.11

PJM evaluates capacity requirements for subregions within 

PJM, or locational deliverability areas (LDAs), in which 

capacity imports are limited by transmission constraints. 

Capacity auction prices will be higher in these areas when 

LDA transmission constraints are forecast to bind in the 

delivery year. 

Increase in Supply Commitments 

and Lower Forecast Load Due to the 

Exclusion of Duquesne Load

PJM’s RPM auctions for 2010-11 and 2011-12 saw increases 

in both new generation and demand resources. In the first 

of the year’s two RPM auctions, a total of 132,191 MW of 

existing and new resources cleared the auction for 2010-

11. Capacity commitments increased by 1,503 MW net of 

forecasted capacity derates for the delivery period. There 

was a 1,776-MW increase in generation capacity, which is 

expected to decrease by 302 MW for generation deratings. 

There was also a commitment for 29 MW in new demandresource capacity.

A total of 132,222 MW of existing and new resources 

cleared the auction for 2011-12. PJM received an increase 

of 3,973 MW of capacity, net of forecasted capacity derates, 

for the delivery period. Commitments for generating 

capacity increased by 3,576 MW (including new generation 

resources and capacity upgrades to existing generation 

capacity resources), which was offset by a forecasted 265-

MW decrease in generation capacity. There was also a 

commitment for a 662-MW increase in new demand-resource 

capacity. This increase in capacity commitment represents 

about two times the new capacity growth compared to the 

2010-11 delivery year, and is the largest increase in capacity 

since the implementation of RPM.

Growth in supply and a drop in demand placed downward 

pressure on PJM’s auction clearing prices. Delivery year 

auction prices dropped from $64/kW-year in 2010-11 to 

$40/kW-year in 2011-12. Notably, PJM assumed no demand 

growth due to the exclusion of 3,000 MW of Duquesne load 

for the 2011-12 delivery period.12

The 2011-12 auction resulted in a uniform clearing 

price throughout PJM because there were no forecasted 

transmission constraints in the LDAs. The 2010-11 auction 

cleared with a uniform clearing price of $64/kW-year, 

with the exception of the DPL-South region of EMAAC (in 

Delmarva Power & Light’s service territory), which cleared 

at $68/kW-year.

NYISO’s Installed Capacity Market

In NYISO’s capacity market, LSEs procure capacity through 

ICAP auctions, self-supply and bilateral arrangements based 

on their forecasted peak load plus a margin. In operation 

since 2000, the NYISO conducts auctions for three different 

service durations: the capability period auction (covering 

a six-month period), the monthly auction and the spot 

11 The first four BRAs, covering delivery years 2007-08, 2008-09, 2009-10 and 

2010-11, are the transition period auctions because they were not conducted 

a full three years before the delivery year. Prior PJM reliability pricing model 

(RPM) auctions, held from April 2007 to January 2008, were held over a 

shortened period – that is, capacity commitments for delivery years 2007 to 

2011 were auctioned over the span of nine months. 

12 Based on Duquesne’s notification that it expected to withdraw from PJM prior 

to the 2011-12 delivery year, Duquesne’s load was excluded from the auction. 

However, most of the generation resources in the Duquesne zone offered their 

capacity into the 2011- auction, resulting in a larger surplus of capacity than 

would otherwise have occurred.
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Figure 32

PJM Quantity of New Resources Cleared 

in Forward Capacity Auctions Held in 2008

Source: Derived from PJM data. 

5000

)

4000

WM( 3000 ytica2000 paC

1000

0

 2010/2011 2011/2012

New demand resources

New generation

New imports

Figure 33

PJM Price Clearing Price For Resources 

Cleared in Forward Capacity Auctions Held in 2008

Source: Derived from PJM data. 

2010/2011 2011/2012

($ per kW-year)

0

20

40

60

market auction.13 NYISO held 2 capability period auctions, 

12 monthly auctions and 12 ICAP spot market auctions in 

2008. 

For the capability period auctions, NYISO calculates an 

unforced capacity (UCAP) amount to determine the capacity 

that each LSE is required to procure. Because UCAP factors in 

the recent level of generator forced outages to ICAP amounts, 

UCAP identifies a smaller level of capacity available to serve 

load requirements.14

NYISO ICAP Market Prices Fell in 2008 

Following New Mitigation Measures and 

Adjusted Load Capacity Requirements

The amount of capacity offered and purchased in NYISO 

exceeded the state’s minimum capacity requirements during 

2008. During the 2008 summer capability period, the 

minimum capacity requirement for New York was 36,633 

MW, while the total amount of capacity sold averaged 

39,729 MW.15 Additionally, beginning in May 2008, New 

York lowered its installed reserve margin requirement to 15 

percent (down from 16.5 percent),16 which yielded lower 

13 New York has capacity requirements for three zones: New York City, Long Island 

and New York – Rest of State. The resource requirements do not change in 

the monthly auctions and ICAP spot market auctions relative to the capability 

period auction. The shorter monthly auctions are designed to account for 

incremental changes in LSE’s load forecasts. The Commission first approved 

an installed capacity market for the NYISO in 2000. New York Independent 

System Operator, 90 FERC ¶ 61,319 (2000).

14 NYISO calculates UCAP by multiplying the ICAP amount by the quantity one (1) 

minus the average effective forced outage rate on demand (EFORd) value for 

the six most recent 12-month rolling average EFORds of New York resources. 

For each capability period, NYISO calculates a UCAP amount for each resource 

qualified to supply capacity. See NYISO tariff, Attachment J, § 1.0.

15 New York Independent System Operator, Inc., 2008 Reliability Needs 

Assessment.

16 The Installed Reserve Margin requirement covered the period from May 

2008 through April 2009. The Installed Reserve Margin is used by NYISO 

to develop its capacity market demand curves. The demand curves, in turn, 

are used in NYISO’s ICAP market auctions to determine each LSE’s installed 

capacity requirement and price. New York Control Area Installed Capacity 

Requirements for the Period May 2008 through April 2009, Technical Study 

Report, December 14, 2007, New York State Reliability Council, LLC. New York 

Independent Operator, Inc., 122 FERC 61,186 (2008).
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minimum capacity requirements. This put downward 

pressure on capacity prices.

Overall, capacity prices decreased in New York in 2008 

compared to 2007. This was particularly the case in New 

York City, where capacity prices for the summer 2008 

capability period (April through September) fell to roughly 

half of the summer 2007 prices, from $12.37/kW-month to 

$6.50/kW-month. In March 2008, the Commission approved 

new market power mitigation measures in the city.17

Following these measures, additional capacity was sold in 

the market, which contributed to the substantial decrease in 

capacity prices. On Long Island, bilateral contracting largely 

determined capacity costs seen by load prices, i.e., virtually 

all of the existing capacity on Long Island has been secured 

by contract. In addition, the local capacity requirement 

in Long Island decreased to 94 percent from 99 percent to 

account for the benefits of the Neptune HVDC line between 

eastern PJM and Long Island.18 This led to a reduction in 

the clearing prices in both the summer and winter capability 

periods.19 While capacity prices in non-New York City areas 

remained roughly $2/kW-month (Figure 34), capacity sales 

in the New York City local capacity zone affect the prices in 

non-New York City areas because capacity sales in the local 

capacity zone of New York City also satisfies the overall New 

York state capacity requirements.

New York Capability Period Auction Prices

Source: Derived from NY-ISO data. 

$0

$2

$4

$6

$8

$10

$12

$14

summer

06

winter

06/07

summer

07

winter

07/08

summer

08

winter

08/09

$ per kW-month

New York City

New York State

Note: Prices are shown in UCAP values. 2008 State of the Market Report, 

NYISO Electricity Markets, Potomac Economics, May 2009.

Figure 34

17 New York Independent System Operator, Inc., 122 FERC ¶ 61,211 (2008), order 

on reh’g, 124 FERC ¶ 61,301 (2008). New mitigation measures were approved 

by FERC in March 2008 and became effective in May 2008. Further, the NYISO 

established new ICAP demand curve parameters that account for the effects 

over time of surplus capacity on capacity revenues New York Independent 

Operator, Inc., 122 FERC 61,064 (2008), order on reh’g, 125 FERC ¶ 61,299 

(2008).

18 The Neptune HVDC line began commercial service in June 2007. Long Island 

Power Authority, http://www.lipower.org/newscenter/pr/2007/062807_

neptune.html.

19 2008 State of the Market Report, NYISO Electricity Markets, Potomac 

Economics, May 2009.
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Section 6 Natural Gas Capacity Release 

and Electricity Transmission 

Reassignment

The Commission has recently reformed the natural gas 

transportation capacity release rules under Order No. 

712 (18 CFR Part 284) and the electric transmission 

service reassignments rules under Order No. 890

(18 CFR Parts 35 and 37) in an effort to increase use of 

the transmission infrastructure and to promote greater 

transparency in wholesale markets.
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Introduction

This chapter summarizes the early results of these reforms 

based on capacity release and capacity reassignment data 

during 2008. The early experience from the capacity release 

reforms suggests that there has been relatively little change 

in capacity release activity. This is partially because the 

period of study includes the winter and the months leading 

up to it when shippers are less likely to release capacity in 

the face of uncertain winter weather. The early experience 

with electric transmission service reassignments suggests 

slightly more change. There has historically been relatively 

little reassignment of electric transmission service. Since 

the reassignment reforms took effect, the quantity of 

transmission service that has been reassigned has increased 

steadily. This increase in reassignments is true across almost 

all dimensions (time, duration of reassignment, number of 

transmission providers reporting reassignments). 

Summary of 

Pipeline Capacity Release Postings

On June 19, 2008, the Commission issued Order No. 712, 

which became effective on July 30, 2008. Order No. 712 

removed the rate ceiling on short-term capacity releases on 

interstate natural gas pipelines.1 The order also modified the 

capacity release rules to facilitate the use of asset management 

agreements (AMAs), removing certain prohibitions on tying 

arrangements and bidding. 

This review provides some initial observations of the first 

six months of the Commission’s revised capacity release 

rules—from Aug. 1, 2008, through Jan. 31, 2009. Because 

of the seasonal nature of the natural gas market, capacity 

releases during this period were compared to those of 

previous years during the same six-month time frame. The 

period covers, primarily, the winter and the months leading 

up to it. Shorter-term decisions about whether to release 

capacity for a day or a month are a function of weather 

conditions, and are therefore as dependent on immediate 

circumstances as on pricing conditions. LDCs, for example, 

would be less likely to release capacity in the face of uncertain 

winter weather. Longer-term decisions to release capacity 

for a year or more tend to occur at or near the beginning of 

the gas year in April and are driven by long-term planning 

within the natural gas cycle.

For the time period selected, above-cap, premium releases 

were compared to releases at or near the cap to identify 

distinctions between the two. Specifically, we discuss the 

volume of releases, the term of releases and the geographic 

dispersion of releases. Next we characterize the nature of 

the entities involved in capacity releases, focusing on the 

extent to which local distribution companies (LDCs) released 

capacity. Finally, we address the change in activity under 

AMAs as a result of the changes in Order No. 712. 

Volume

Removal of the price cap for released pipeline capacity has 

not substantially altered the capacity release market. Slightly 

more capacity was released in the first six months after 

Order No. 712 became effective than during the same period 

in 2007-08, but less than the prior year (see Figure 35). This 

pattern is consistent with the winter weather conditions in 

those years, with 2007-08 being the most severe, thereby 

accommodating fewer releases. The biggest difference in the 

releases among the years was in below-the-cap releases. In 

2006-07, 57 percent more discount releases occurred and 28 

1 Promotion of a More Efficient Capacity Release Market, Order No. 712, 73 Fed. 

Reg. 37,058 (June 30, 2008), FERC Stats. & Regs. ¶ 31,271 (2008).
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percent more discount capacity was released than in 2007-

08. In 2007-08, maximum-priced releases were about equal 

to discount releases, both in number and capacity released. 

In 2008-09, while there were fewer at-the-cap releases than 

discount releases, the addition of premium-priced releases to 

the at-the-cap releases nearly evens the count.

Figure 35

Capacity Release Rate Comparision 6 Months

After Order No. 712 vs. Previous Years

Source: Derived from Energy Velocity data. 

0

5000

10000

15000

20000

25000

MMDth/Releases

Premium

At or near tariff rate

Discount

Near 0

06-07 07-08 08-09 06-07 07-08 08-09

Capacity Released Number of Releases

Term

The term of the capacity releases changed little between 

2007-08 and 2008-09, even with the availability of premiumpriced releases. Two-thirds of the capacity releases in both 

years were for terms of one month. In 2007-08, a higher 

percentage of the number of releases occurred for terms 

less than a month (15 percent in 2007-08 versus 8 percent 

in 2008-09), but the volume of capacity released for these 

shorter periods amounted to little of the capacity released in 

either year (less than 1 percent). In the part of the capacity 

release market still capped at the tariff rate after Order No. 

712 (over one year), there were roughly the same number of 

long-term and permanent releases in both years.

Looking solely at the releases above the cap in 2008-09, 59 

percent of the premium-priced capacity released was for one 

year, the longest duration allowed under Order No. 712. By 

comparison, 58 percent of the capacity released at the tariff 

rate was for a period longer than one year. 

Geographic Concentration

Geographically, most of the capacity released occurred on 

pipelines serving the Northeast and Midwest. About half 

of the capacity released on Northeast pipelines was at the 

tariff rate cap, and another 6 percent was above the cap. 

In contrast, 77 percent of capacity released on Midwest 

pipelines was discounted (see figures 36 and 37). Although 

there were fewer total releases in the Midwest than in the 

Northeast, half the releases above the cap in 2008 were on 

pipelines serving the Midwest. The number of below-cap 

releases on Northeast and Midwest pipelines stayed roughly 

the same across 2007-08 and 2008-09. 

Figure 36

Capacity Releases by Region During July vs. August

Dths Released

Source: Derived from Energy Velocity data. 

0

1000

2000

3000

4000

5000

6000

7000

Northeast Southeast Midwest Producing

(SW)

Rockies West

MMDth

Premium

At or near tariff rate

Discount
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Figure 37

Capacity Released by Region July vs. August

Number of Releases

Source: Derived from Energy Velocity data. 

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

Northeast Southeast Midwest Producing

(SW)

Rockies West

MMDth

Premium

At or near tariff rate

Discount

Releasing Shippers

In both 2007-08 and 2008-09, LDCs participated in more 

capacity releases than other types of market participants: 44 

percent of the releases in 2007-08 and 49 percent in 2008-09 

(see figure 37). Even though Order No. 712 eliminated the 

price cap late in the gas year after the current year’s plans 

had been fixed, LDCs were responsible for 40 percent of the 

above-the-cap releases in the first six months after the order. 

Releases by integrated utilities that may have been part of 

the gas LDC function accounted for another 15 percent of 

the post-order above-the-cap releases. The total number of 

releases by LDCs and integrated utilities fell by about 300 (5 

percent), but the amount of capacity they released increased 

by 25 percent. This may indicate that the decline occurred in 

shorter-term releases, which would be most affected by the 

severity of the winter. Companies identifiable as marketers 

accounted for a little over 10 percent of the releases in both 

years but almost 20 percent of the premium releases after 

Order No. 712.

Figure 38

Capacity Releases by Releaser Type

Source: Derived from Energy Velocity data. 

0

2000

4000

6000

8000

10000

12000

MMDth

Discount

Premium

At or near tariff rate

2. Int. Utility

3. End user 

 

1 2 3 4 5 6 7 1 2 3 4 5 6 7

4. Elec. Gen.

5. Producer

6. Marketer

7. Other

 1. LDC

2007-2008 2008-2009

In Order No. 712, the Commission created exemptions to 

the capacity release rules to accommodate the development 

of asset management agreements (AMA). In an attempt 

to capture AMA activity, we compared customer/agent 

information in the index of customers to releaser/bidder 

information in the capacity release database.2 

Instances where the bidder is identified as a pipeline 

customer’s agent constitute a small share of the capacity 

release market, but that share did double during the six 

months after Order No. 712 to almost 3 percent of the releases 

and nearly 5 percent of the capacity released in 2008-09. 

The largest growth occurred in long-term released capacity, 

which tripled between the two periods. Initial research from 

the Office of Enforcement’s audit staff indicated that AMAs 

tend to be executed near the beginning of the gas year, 

on April 1. This would mean that data still coming in will 

provide a more robust picture of Order No. 712’s effect on 

the AMA market.

2 In pipelines’ index of customers, the pipeline defines an agent for a customer as 

“the name of any agent or asset manager managing a shipper’s transportation 

service ” (18 CFR Sec 284.13(c)(2)(viii)). This relationship is consistent with the 

relationship necessary to affect an asset management agreement where the 

customer prearranges a capacity release with its agent/manager bidding for 

the capacity. 
2008

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Summary of 

EQR Capacity Reassignment Filings

Market participants that had reserved transmission service 

have been allowed to reassign that service above the tariff 

rate since Order No. 890 went into effect during the second 

quarter of 2007.3 In addition to allowing transmission service 

reservation (TSR) reassignments, Order No. 890 also requires 

that electric transmission providers report in their quarterly 

EQR filings reassignment of TSRs for service reserved under 

the transmission provider’s open access transmission tariff. 

The requirement is designed to promote transparency in 

transmission markets, similar to the requirement that natural 

gas pipeline companies post capacity releases on their 

pipelines.

There has historically been relatively little reassignment of 

electric transmission service. Since second-quarter 2007, the 

quantity of transmission service that has been reassigned 

has increased steadily. This increase in reassignments is 

true across almost all dimensions. That is, the number of 

transmission providers reporting reassignments has increased; 

the number of TSRs reassigned for each particular duration 

(e.g., hour, daily, monthly, yearly) has increased; and the 

capacity (in MWhs of service) reassigned has increased. TSR 

reassignments occurred throughout the non-RTO markets, 

with no particular region standing out. The majority of 

completed TSR reassignments were for less than a day, 

though on a MWh-basis, yearly and monthly reassignments 

make up the vast majority of reassignments. We are unable 

to fully address the pricing of TSR reassignments because 

any entities reassigning TSRs failed to report a price other 

than zero.

Capacity Reassignment Sales

The reporting of capacity reassignments began in 2Q07, and 

has subsequently increased both in the number of providers 

reporting and in the volumes reported. The data reported 

herein include all quarterly EQR submissions made through 

fourth-quarter 2008. 

During the 7 quarters analyzed, 19 market participants 

transacted 1,554 capacity reassignments under contract and 

169 without contracts, for a total of 1,723 transactions.4

Twenty-two of the 1,723 reported transactions involved 

sales between affiliates. These are shown by provider and 

by quarter in Table 6.

Table 6

Reassignments by Transmission Provider by Quarter

2Q 3Q 4Q 1Q 2Q 3Q 4Q Total 

07 07 07 08 08 08 08

BPA - - - - - - 715 715

Cross-Sound Cable 103 15 16 23 36 27 20 240

Mid_Continent PP -30 33 33 33 33 33 195

NW Energy - - 8 12 14 63 70 167

Southern Co. - 22 17 13 48 20 120

Entergy - 34 - - - 6 6 46

PacifiCorp	 1	 1	 1	 1	 2	 13	 24	 43

MISO 2 3 6 9 11 4 6 41

TEC - - - - - - 40 40

APS - - - - 6 12 12 30

NUSCO (as Agent)* - - - 6 6 6 10 28

PSNM - - - - 4 7 7 18

Idaho Power - - - - - 7 7 14

SPP - - - 2 2 2 4 10

NU Services Co. 2 2 2 - - - - 6

MidAmerican - - 1 1 1 1 1 5

NVP - - - - - 1 2 3

Puget Sound - - - - - - 1 1

EPE - - - - - 1 - 1

108 107 84 100 163 203 958 1,723

*NUSCO reported as the joint agent for WMECO and HWP in these transactions.

Source: Derived from EQR data.

3 Preventing Undue Descrimination and Preference in Transmission Service, 

Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, 

FERC Stats. & Regs. ¶ 31,261 (2007), order on reh’g, Order No. 890-B, 123 

FERC. ¶ 61,299 (2008) order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228 

(2009). Market participants that have reserved transmission service have been 

allowed to reassign that service reservation since Order No. 888 initiated the 

Commission’s current electric transmission service regime. 4 Contracted transactions tie to an existing reassignment agreement on file

with the Commission, whereas uncontracted transactions do not.
2008

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The total number of reported TSR reassignments was roughly 

steady through 1Q08, but increased significantly in the 

remainder of 2008. The number of reassignments reported 

by specific transmission providers has varied greatly from 

one quarter to the next. For example, in the fourth quarter 

of 2008, an unusually large number of transactions was 

reported by Bonneville Power Administration (BPA), most 

of which involved reassignments by two counterparties.5 As 

BPA’s reassignments represent approximately 75 percent of 

the total reported for that quarter, their appearance masks 

the fact that the remaining 243 assignments represent a 225 

percent increase in transactions reported since the second 

quarter of 2007.

In contrast to the number of TSRs reassigned, the capacity of 

the TSRs reassigned (in MW) has increased through 2007 and 

remained fairly steady until 4Q08, when BPA’s reassignments 

were reported. As shown in Table 7, the amount of capacity 

reassigned increased from 3,576 MW in 2Q07 to 8,821 

MW in 4Q08, amounting to 39,430 MW across the seven 

quarters studied. BPA’s sales added a sizable portion (about 

22 percent) of the 4Q total, making them the ninth largest 

supplier despite contributing sale reassignments in only one 

quarter.

Table 7

Capacity Reassigned by Transmission Provider

by Quarter (in MW)

2Q 3Q 4Q 1Q 2Q 3Q 4Q Totals

07 07 07 08 08 08 08

 

Mid_Continent PP 1,448 1,698 1,698 1,698 1,698 1,698 9,936

Cross-Sound Cable 1,540 596 885 950 800 775 540 6,086

Southern Co. 1,393 300 587 1,222 712 100 4,314

NUSCO (as Agent) 665 665 665 1,115 3,110

NW Energy 274 501 617 549 762 2,703

SPP 500 500 500 1,000 2,500

MISO 102 153 306 558 660 303 405 2,487

NU Services Co. 665 665 665 1,995

BPA 1,913 1,913

Entergy 1,254 50 199 199 1,702

NVP 297 297 594

PacifiCorp	 15	 15	 15	 15	 30	 196	 206	 492

MidAmerican 87 87 87 87 87 435

PSNM 94 161 161 416

APS 80 100 100 280

Idaho Power 129 129 258

EPE 100 100

Puget Sound 82 82

TEC 27 27

 

Totals: 3,576 4,320 4,230 5,561 6,453 6,471 8,821 39,430

Source: Derived from EQR data.

The vast majority of reassigned capacity occurred on a small 

number of systems. Overall, more than half (51.5 percent) 

of all capacity reassigned occurred on three systems and 93 

percent of the total capacity reassigned was on 10 systems.

5 Those two counterparties were Shell and Powerex Corp.
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Duration of Transmission Capacity 

Reassignment Transactions

The majority of TSRs reassigned were for an hour. However, 

as shown in Table 8, the trend shows that the number of 

transactions made for all durations (hourly, daily, monthly 

and annually) has increased with time. The large number of 

transactions reported by BPA in the fourth quarter of 2008 

(714) skewed the number of hourly reassignments reported for 

that period. Figure 39 provides a graphical presentation of 

the duration of TSR reassignments, with BPA reassignments 

excluded. 

Table 8

Number of Reassigned Transmission Capacity 

Transactions Grouped by Duration

Hours Days Months Years Total

2Q-07 103 0 4 1 108

3Q-07 76 9 21 1 107

4Q-07 56 9 8 11 84

1Q-08 65 5 13 17 100

2Q-08 114 6 21 22 163

3Q-08 112 28 33 30 203

4Q-08 847 31 39 41 958

Total 1,373 88 139 123 1,723

Figure 39

Duration of Transmission Capacity Reassignment Transactions 

by Quarter (Excludes 714 Transactions of BPA in 4Q 2008)

Source: Derived from EQR data. 

0

50

100

150

200

250

2Q-07 3Q-07 4Q-07 1Q-08 2Q-08 3Q-08 4Q-08

Transactions

Years

Months

Days

Hours

Table 9 presents the volume of the capacity reassigned 

by quarter, exclusive of BPA reassignments. Although 

the number of hourly reassignments predominates in all 

transactions, the volumes of the longer-term transactions 

are significantly larger, as would be expected. In total, more 

than 186 TWh was reassigned. 

Table 9

Reassigned Transmission Capacity (GWh) 

Quarter Hours Days Months Years Total

 

2Q-07 21 0 5,904 52 5,977

3Q-07 77 30 6,360 131 6,599

4Q-07 52 25 6,092 12,828 18,996

1Q-08 54 20 4,944 25,596 30,614

2Q-08 86 37 5,642 26,697 32,461

3Q-08 100 84 6,888 29,482 36,555

4Q-08 124 88 10,892 43,730 54,834

Total 514 284 46,722 138,517 186,036

Source: Derived from EQR data.

Geographic Dispersion of Transmission 

Capacity Reassignment Transactions

Nineteen transmission providers and 27 buyers have 

participated in the market to date. The capacity has been 

reassigned from 25 sourcing control areas to 28 sinking 

control regions. The transactions are grouped by sourcing 

region in Table 10 and by sinking region in Table 11 (both 

on next page). Large influence of BPA transactions is again 

present, reflected in the large percentage of transactions in 

the Northwest. 
2008

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Table 10

Regional Distribution of Capacity 

Reassignment Transactions by Source

Region Sources Transactions % of Total

Midwest 4 236 14%

Northeast 4 311 18%

Northwest 5 888 52%

Southeast 9 208 12%

West 3 80 5%

Total 25 1723 100%

Source: Derived from EQR data.

Table 11

Regional Distribution of Capacity 

Reassignment Transactions by Sink

Region Sinks Transactions % of Total

Midwest 6 200 12%

Northeast 4 283 16%

Northwest 6 936 54%

Southeast 6 173 10%

Southwest 3 66 4%

West 5 65 4%

Total 30 1723 100%

Source: Derived from EQR data.

Price of Transmission Capacity 

Reassignments Relative to Tariff Rates

We are unable to fully address the pricing of TSR reassignments 

because many entities reassigning TSRs failed to report a 

price other than zero.6 Specifically, 447 reassignments 

reported a price of zero across the seven quarters, with 

14 others failing to report a tariff maximum rate. Of the 

remaining 1,262 reassignments, 859 (68 percent) occurred 

below the maximum rate, 158 (13 percent) occurred at the 

maximum and 245 (19 percent) transacted above the tariff, 

as permitted by Order No. 890. We note that 42 percent of 

the reassignments above the tariff rate occurred in the second 

quarter of 2007. These data are shown in Table 12. The 714 

transactions reported by BPA in the fourth quarter of 2008 

again skews the visual analysis of transactions reported, 

contributing 713 transactions to the “< 50%” category. 

Table 12

Transmission Capacity Reassignments Rate Charged 

Relative to Maximum (by Quarter)

 50%- 100%- 

 NR 0% <50%* 100% 200% 200% >200% Total

2Q-07 - 4 1 - - 89 14 108

3Q-07 - 57 1 - 34 6 9 107

4Q-07 - 58 1 - 9 13 3 84

1Q-08 1 61 1 - 13 9 15 100

2Q-08 3 98 2 1 22 29 8 163

3Q-08 5 70 15 49 36 23 5 203

4Q-08* 4 99 26 49 44 21 1 244

Total* 13 447 47 99 158 190 55 1,009

Source: Derived from EQR data.

* Total excludes 714 transactions reported by Bonneville Power Authority.

6 This is likely a reporting mistake by customers reporting reassignments to 

transmission providers.
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Section 7 Infrastructure Additions Ease 

Gas Grid Congestion and Alter

Transportation Differentials

Natural gas infrastructure burgeoned in 2008. 

There were significant additions in both interstate and 

intrastate infrastructure. EIA estimated that in 2008, 

new interstate and intrastate gas infrastructure projects 

added an unprecedented 43.9 billion cubic feet per 

day (Bcfd) of pipeline capacity, almost three times the 

capacity additions from previous years.
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Introduction

The magnitude of the pipeline projects, with 15 projects each 

designed to transport more than 1 Bcfd, is significant. The 

Commission certificated over 35 interstate pipeline projects. 

In addition, three new North American LNG terminals – 

Freeport and Sabine Pass in Louisiana and Northeast Gateway 

(NEG) offshore Boston1 – began service. 

Many of the new pipelines served to better integrate robust 

unconventional natural gas production into the national 

pipeline grid. As a result, some of the most significant 

pipeline capacity additions altered traditional flow patterns 

and transformed physical transportation price relationships. 

These changes were especially noteworthy in the Western, 

Northeastern and Gulf regions (see Figure 41). 

Natural gas storage capacity also experienced robust growth 

in 2008. The Commission approved 216 Bcf of additional 

storage capacity and 7.8 Bcfd of deliverability.2 Nearly 73 

percent of the additional storage capacity was concentrated 

in the Gulf and Midwest regions (see Figure 40). 

Figure 40

EIA Estimates Total Natural Gas Pipeline 

Capacity Additions

Source: Derived from EIA,GasTran Natural Gas Transportation Information System, Natural 

Gas Pipeline Projects database as of Jan 2009.

0

5

10

15

20

25

30

35

40

45

50

98 99 00 01 02 03 04 05 06 07 08

Bcfd

1 Freeport and Sabine Pass are under the jurisdiction of the FERC and the 

Northeast Gateway LNG facility is under the jurisdiction of the United States 

Coast Guard and the Maritime Administration.

2 Of the projects the Commission approved, 82 Bcf of additional storage capacity 

was placed in service and 5 Bcfd of storage deliverability was placed in service 

in 2008. Nearly 90 percent of the additional storage capacity placed in service 

was located in the Gulf and Midwest regions.

Figure 41 

2008 Natural Gas Storage, Pipeline, and LNG Projects 

Source: FERC Office of Energy Projects.
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Regional Analysis

New infrastructure had pronounced effects on regional gas 

flows and pricing in 2008, especially in the Gulf-Ohio Valley, 

Rockies-Midwest and East Texas-to-Southeast corridors. 

Gulf – Ohio Valley Corridor

Northeast pipelines have added little new capacity in recent 

years and periodic winter cold snaps have constrained the 

pipeline system. In 2008, pipelines added more than 2 Bcfd of 

capacity to transport additional Canadian LNG, Mid-Atlantic 

shale and Gulf gas into the Northeast market. Much of the 

newly added capacity was instrumental in transporting gas 

directly into the New York City metro area. During peak 

demand days, the New York City market area can become 

heavily constrained, and natural gas spot prices can become 

extremely elevated at the Transco Zone 6 New York (NY) 

pricing hub. A series of pipeline projects in the Northeast 

helped alleviate such gas bottlenecks into the Transco Zone 

6 NY market and moderate price volatility.

Figure 42 details the recent major Northeast pipeline and 

LNG projects addressing pipeline congestion and growing 

Northeast winter demand. To provide context for the 

size of the these projects, during winter 2008 natural gas 

demand peaked at 35.1 Bcfd and averaged 20.3 Bcfd. A 

series of new pipeline additions and expansion projects 

enabled more Canadian gas to make its way into the New 

York metro area. For example, the Empire Connector came 

into service in December 2008, adding 250 MMcfd to the 

existing pipeline. Most of this gas comes from TransCanada 

PipeLines at the Canadian border and gets delivered into the 

Millennium Pipeline at Corning, N.Y., which transports the 

Canadian gas farther south into the New York metropolitan 

area. The Millennium Pipeline entered service in December 

2008 and is currently flowing on average 270 MMcfd of its 

525 MMcfd capacity. Algonquin’s Ramapo Expansion was 

built to take advantage of market opportunities provided by 

the Millennium project. The Ramapo Expansion receives 

gas from an interconnect with Millennium. The expansion 

enables it to flow gas from Millennium and deliver it to the 

new Brookfield interconnect with Iroquois or, if needed, it can 

deliver the additional gas farther downstream to Boston.

In addition to the natural gas pipeline expansions, there 

were several LNG import projects. In May 2008, Excelerate 

Energy’s Northeast Gateway (NEG) LNG facility began 

commercial operations and received its commissioning 

cargo. In January 2009, the New England Maritimes Phase 

IV pipeline expansion increased capacity by 418 MMcfd to 

help the Northeast market access LNG at the Canaport facility 

in New Brunswick when it began receiving cargos. 

Figure 42

Recent Major Northeast Interstate Natural

Gas Pipeline and LNG Projects

Pipeline In service MMcfd

1 Empire Connector 12/15/08 250

2 Millennium Pipeline 12/22/08 525

3 TETCO Time II 12/10/08 150

4 Sentinel Project 12/23/08 40

5 Algonquin Ramapo 11/01/08 352

7 Maritimes Phase IV 1/15/09 480

LNG

6 Northeast Gateway LNG 05/17/08 800
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Transportation cost differentials (basis) from Transco Z3 on 

the Gulf Coast to Transco Z6 NY during winter 2008-09 

changed dramatically from the previous winters. Winter 

2008-09 basis averaged $1.90/MMBtu compared with the 

winter 2007-08 basis that averaged $2.60/MMBtu. This 

27% drop in average daily basis resulted from a decline 

in commodity prices and an increase in infrastructure 

throughout the region and into the New York metro market 

area. This drop occurred despite Transcontinental Gas Pipe 

Line (Transco) operating at reduced capacity for much of the 

winter due to a rupture on its system near Appomattox, Va. 

Figure 43 

Southeast Exports into the Ohio Valley 

and Transportation Diơerentials 

Source: Derived from Bentek Energy and IntercontinentalExchange data. 

0

1

2

3

4

5

6

7

8

9

10

1-07 5-07 9-07 1-08 5-08 9-08 1-09

Scheduled Flows (Bcfd)

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

$10

SE Exports into OV

$/MMBtu

Tetco M3-WLA Spot Basis Capacity

Conversely, transportation differentials between Texas 

Eastern Transmission’s Tetco WLA (in western Louisiana) and 

Tetco M3 (near New York) during winter 2008-09 averaged 

$1.55/MMBtu, $0.15/MMBtu greater than winter 2007-08. 

This 10 percent increase in average daily basis cost was the 

result of more gas flowing through the Ohio Valley on Texas 

Eastern and into the Northeast market (see Figure 43), thus 

increasing the frequency of constraint-driven price spikes 

during a colder-than-normal winter. Gas flows through the 

Ohio Valley increased by 723 MMcfd, or 11 percent, with a 

portion of the additional supply being made up of shale gas 

from the Marcellus region. Overall, average 2008 gas flows 

into the Northeast increased by 476 MMcfd, or 3 percent, 

despite supply decreases from Canada and the Midcontinent 

(both were off 9 percent from the previous year). 

Rockies – Midwest Corridor

The western region of the country also experienced significant 

growth in new pipeline capacity. In January 2008 Kinder 

Morgan finished Phase II of the Rockies Express Pipeline 

(REX), which is capable of transporting 1.5 Bcfd of natural 

gas from the Cheyenne Hub in Wyoming to Audrain County, 

Mo. REX established new interconnections with a number 

of pipelines serving the Midwest market, including Northern 

Natural, Panhandle, ANR and Kinder Morgan Interstate Gas 

Transmission (KMIGT). 

Figure 44

Flows on REX II West and Transportation 

Diơerentials

Source: Derived from Bentek Energy and IntercontinentalExchange data. 

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

1.8

 06-07 09-07 12-07 03-08 06-08 09-08 12-08

$1

$0

$1

$2

$3

$4

$5

$6

$7

$/MMBtu

Daily Scheduled Volume Pahandle - 

Available Capacity CIG Basis

Before REX II After REX II

REX’s extension into the Midwest has had substantial effects 

on gas flows and Midcontinent basis differentials. As 

expected, REX provided shippers in the Midwest greater access 

to Rockies gas. Exports from the Rockies to the Midwest via 

REX grew by 1.1 Bcfd in 2008 (see Figure 44). As Rockies 

gas flowed into the Midcontinent region, transportation 

differentials between the Rockies and Midcontinent fell. For 
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instance, the basis between the CIG Mainline (in Colorado) 

and Panhandle (in Oklahoma) markets fell by 68 percent 

($1.39/MMBtu) from the previous year.

The increased flow of gas out of the Rockies displaced up to 

600 MMcfd of natural gas from Midcontinent and Permian 

basins along the El Paso, Transwestern, Northern Natural 

and NGPL pipelines. Gas from Midcontinent basins was 

rerouted to markets in California and the desert Southwest. 

In 2008, gas deliveries from the Midcontinent on El Paso 

and Transwestern contributed to an average increase of 

550 MMcfd of gas available for the Southwest market. In 

turn, this increased flow into the Southwest and Southern 

California reduced prices in Southern California. Shippers 

fully utilized PG&E’s Baja Path linking Southern California 

receipt points with delivery points farther north in California 

to take advantage of lower-cost gas. As the Baja Path became 

constrained, transportation differentials between the SoCal 

border and PG&E citygate markets reached historically large 

levels. On Oct. 12, 2008, that transportation differential 

reached an all-time peak of $3.60/MMBtu compared to 

the previous year’s daily peak of $2.44/MMBtu. Average 

daily utilization along the Baja Path increased 86 percent 

(to 982 MMcfd of 1,140 MMcfd of design capacity) in 2008 

compared to 74 percent in 2007, with daily flow often 

reaching maximum capacity. In addition, displaced Western 

Canadian Sedimentary Basin gas and additional supplies to 

the Southwest together established big storage surpluses in 

Canada and the western United States.

Rockies gas flows into the Midcontinent regions also 

marginalized Canadian gas imports, especially in the Midwest. 

Natural gas imports into the Northern Border pipeline fell 13 

percent to 1.63 Bcfd from 1.87 Bcfd between 2007 and 2008. 

Average daily flows into the Northern Border interconnect 

with Northern Natural at Ventura, Iowa, averaged 0.5 Bcfd 

lower in June 2008, when REX deliveries into the Midwest 

peaked. In short, Canadian gas – formerly the lowest-cost 

gas supplied to the Midwest – became the marginal source 

of supply. 

The next REX phase, REX III East, pushed beyond the 

previous terminus in Missouri to Lebanon, Ohio. Service 

began in June 2009. REX III East is expected to be fully 

operational by Nov. 1, 2009, with a capacity of 1.8 Bcfd. 

East Texas – Southeast Corridor

Unprecedented construction of gas infrastructure took place 

along the Gulf Coast in 2008. A slew of pipeline projects 

came online, intended primarily to deliver increased shale 

gas volumes from the Woodford, Barnett, Haynesville and 

Fayetteville plays to downstream markets in the Southeast 

like FGT Zone 3 and Transco Station 85 (see Figure 45). 

Four new FERC-jurisdictional storage facilities expanded to 

add 36 Bcf of working capacity and the expansion of three 

existing facilities expanded to add 9 Bcf. Storage capacity 

increases in the Gulf Coast accounted for more than 50 

percent of storage capacity increases in the nation in 2008.

Figure 45

2008 Major Gulf and Southeast Interstate 

Natural Gas Pipeline and LNG Projects

Pipeline 
2008

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Nearly 4 Bcfd of takeaway capacity out of the Gulf region 

was added during 2008. Gulf South’s Southeast Expansion 

project and Southeast Supply Header (SESH) added 1.7 Bcfd 

of delivery capacity (see Figure 46). These new Gulf South 

projects (Southeast Expansion and East Texas-to-Mississippi) 

and other similar Gulf pipeline projects transport Texas 

and Oklahoma shale gas farther east to Transco Station 85 

and beyond. The more northern Fayetteville Lateral, which 

began service last December, flows gas from the Arkansas 

Fayetteville Shale. Initially, the pipeline delivered most of 

its gas into NGPL but subsequent tie-in work with the Texas 

Gas Mainline shifted flows and now most of the 700 MMcf 

is delivered into Texas Gas Mainline. These new pipelines 

provide significant interconnectivity with many larger 

pipelines such as Transcontinental, Texas Gas Mainline, 

Texas Eastern and Columbia Gulf, whose routes terminate in 

the Ohio Valley and Northeast markets. 

The influx of cheaper shale gas into the pipeline grid altered 

basis relationships throughout the region. The SESH delivers 

90 percent of its gas to serve Florida load. The added 

diversity of East Texas shale gas to the Florida supply mix 

has helped to stabilize Florida prices, decrease the severity 

of Florida natural gas price spikes and reduce overall 2008 

average basis between Carthage, Texas, and Florida Zone 3. 

In 2008, there were fewer days of high basis compared to 

2007. In 2008, the number of days where the basis between 

Carthage and Florida Zone 3 exceeded $0.50/MMBtu declined 

26 percent (71 days) from the prior year (see Figure 46). 

While September 2008 basis reached $5/MMBtu because 

of pipeline shut-ins following hurricanes Gustav and Ike, 

the new pipeline capacity helped keep average 2008 basis 

17 percent ($0.15/MMBtu) lower than the previous year. 

With all the additional pipeline capacity that transports gas 

farther east into Transco Station 85, the 2008 Transco Zone 

4 transportation differential to the Henry Hub was $0.17/

MMBtu, the lowest it’s been since 2004. 

We will likely see another year of extraordinary capacity 

additions in 2009. Phase I of Gulf Crossing pipeline began 

service in January 2009 and peak sendout to Texas Gas Pipeline 

reached 800 MMcfd in early May. The 1.8-Bcfd Midcontinent 

Express pipeline entered partial service on April 10, 2009, 

and follows the same path as the Gulf Crossing pipeline. 

Two pipelines of this magnitude positioned along the same 

corridor are indicative of the abundance of shale gas supply. 

Texas Gas Greenville Lateral received authorization to begin 

flowing volumes and in conjunction with the Fayetteville 

Lateral, provides Arkansas Fayetteville Shale gas to more 

premium markets in the Southeast, Gulf and Northeast via 

pipelines such as Texas Eastern and Columbia Gulf. Dockets 

on file with FERC’s Office of Energy Projects confirm that 

the next few years will continue to show robust growth in 

Gulf and Southeast natural gas infrastructure. 

Figure 46

Flows From Perryville to SE and 

Transportation Diơerentials 

Source: Derived from Bentek Energy and IntercontinentalExchange data. 

5 $7

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06-07 09-07 12-07 03-08 06-08 09-08 12-08 

Scheduled Volumes

Capacity

FGTZ3-Carthage Basis SESH

Gulf South SE 

Expansion

Gulf South ETX to MS
2008

State of the Markets Report

FEDERAL ENERGY REGULATORY COMMISSION

www.ferc.gov/oversight

79

Acknowledgments

Researching, writing and producing the 

2008 State of the Markets Report was a group effort that required 

many hours of hard work. No acknowledgements list can do justice 

to the impressive efforts of so many people. 

The principal authors of this report include:

Connie Caldwell, Keith Collins, Christopher Ellsworth, 

Jeffrey Honeycutt, Shaun Ledgerwood, Kenneth Kohut, Kamaria 

Martin, Christopher Peterson, Steven Michals, Susan Pollonais, 

J. Arnold Quinn, Steven Reich, William Sauer, Bikash Thapliya, 

Maria Vouras, Carol White

Those that provided extensive research and production support include:

William Booth, Florence Bresnahan, Ramses Cabrales, Christopher Cafiero, 

Judy Eastwood, Alan Haymes, Lance Hinrichs, Matthew Hunter, 

John Jennrich, Ryan Jett, Gary Mahrenholz, Eric Primosch, Astrid Rapp, 

Thomas Rieley, Saida Shaalan, Timothy Shear, Sonia Sylvanovich, Ben Ullman

Disclaimer: The opinions and views expressed in this staff report do not necessarily 

represent those of the Federal Energy Regulatory Commission, its Chairman, 

or individual Commissioners, and are not binding on the Commission.

This staff report contains analyses, presentations and conclusions that may 

be based on or derived from the data sources cited, but do not necessarily 

reflect the positions or recommendations of the data providers.