1

Item No: A-3

April 15, 2010

Federal Energy Regulatory Commission

State of the Markets State of the Markets

Report 2009 Report 2009

Each year, the Division of Energy Market Oversight in the Office of Enforcement 

presents a State of the Market report reviewing how the significant events of the past 

year better inform our understanding of the current and future energy markets.
2

State of the Markets State of the Markets 

2009

 Adjustments to a global recession

 A new gas paradigm emerges

 California embarks on a new market

 Congestion costs decrease

Energy markets underwent considerable change in 2009

The deep global recession was reflected in reduced demand, lower prices, and slowed 

investment.  During the year, long‐standing price relationships between fossil fuels 

changed affecting decisions made for their use.

A new gas market paradigm emerged into clearer focus.  This paradigm may change 

the way we look at future energy choices.

California ISO initiated its new nodal market on March 31; and

The cost of electric congestion decreased across the country.
3

2009 Gas Prices Started 2009 Gas Prices Started 

Low and Moved Lower Low and Moved Lower

Henry Hub Natural Gas Daily Price ($/MMBtu)

$0

2

4

6

8

10

12

$14

2008

2009

Source: ICE J FMAMJ J A S OND

In 2008, a global commodity bubble pulled energy prices to unprecedented levels, 

peaking just before the Fourth of July.  When capital began flowing out of commodity 

markets, prices began falling and continued doing so as economies around the world 

plunged into recession.

In contrast, 2009 natural gas prices started relatively low and moved lower. Mild 

weather, the effects of the recession, record storage inventories filling record storage 

capacity and supply abundance pushed prices to levels not seen since 2002.  Late in the 

year, with the advent of winter, gas prices moved back up to their early‐2009 levels.

Interestingly, gas demand was relatively steady between 2008 and 2009 as a 5.5 

percent increase in demand for gas for electric generation offset declines in the 

residential, commercial and industrial sectors.
4

Gas Prices Lower Gas Prices Lower 

Across the U.S. Across the U.S.

Sumas

$3.77

-54%

SoCal

$3.62

-54%

AECO

$3.48

PG&E -55%

$4.13

-52%

Opal

$3.14

-52%

Panhandle Panhandle 

$3.27

-54%

HSC

$3.75

-56%

Henry

$3.92

-56%

Chicago

$3.92

-55%

TCO

$4.11

-55%

TZ6 NY

$4.87

-52%

FGT Z3

$3.98

-57%

Source: Derived from ICE data.

Prices were not just lower at Henry Hub.  Across the U.S., average gas prices were 

down more than 50 percent from 2008 to 2009.  These price changes were largely 

driven, on a year‐to‐year basis, by the drop in commodity costs.  New pipelines added

during the course of the year did affect price relationships among regions for portions 

of the year.  I will discuss those effects later.
5

Electricity Demand Electricity Demand 

Dropped Considerably Dropped Considerably

Industrial Only Industrial Only

50

75

100

J MM J S N

250

275

300

325

350

375

JM J SN M

All Sectors All Sectors

000 GWh

2006

2007

2008

2009

Source: Derived from EIA data.

The recession left its mark on the electric market.  Demand for electricity dropped by 

4.2% in 2009.  This was the greatest decline in a single year in at least 60 years and, 

with 2008, the only time electricity demand has fallen in consecutive years since 1949.  

Falling power demand is rare.  There have been 11 recessions since 1949; power 

demand fell only during three of them. 

The drop in demand was largely due to a sharp decline in the industrial sector which 

was hit hard by the recession. As in many of the previous recessions, there was a 

discernable reduction in industrial demand. Industrial customers used less power than 

in any year since 1988.  Unlike many earlier recessions, residential and commercial 

demand also fell, about 1% together.

Demand was also reduced by mild summer weather for most of the country.  Yet, even 

on the most extreme days, electricity demand failed to approach historic levels.  The 

primary exception to this characterization was in ERCOT where demand records were 

broken twice in July in spite of a large decline in Texas industrial demand.  The ERCOT 

system performed reliably and no interruptible resources were dispatched on either 

day.  

Continued on Next Page
6

Continued From Previous Page

With the recession and mild weather dampening demand, it is difficult to isolate the 

effect of energy efficiency and demand response programs.  These programs are 

beginning to have a presence in many RTOs. Some allow demand response resources 

to be bid into the capacity market.   In PJM, ISO‐New England and the New York ISO, 

the amount of demand resources cleared through the capacity markets grew to 12 GW. 

Five states (Iowa, Delaware, Indiana, Arizona, and Massachusetts) added Energy 

Efficiency Resource Standards (EERS) in 2009, bringing the total number of states with 

EERS to 23.  Two of these new EERS states, Arizona and Delaware, include peak 

reduction targets from demand response programs, joining nine other states with 

similar provisions.    EERS are pending in 4 states (NJ, FL, UT, WI).  This count of EERS 

states does not include West Virginia and Virginia, which have non‐binding energy 

efficiency goals instead of EERS.
7

Wholesale Electricity Wholesale Electricity 

Prices Also Declined Prices Also Declined

Mid-Columbia

$35.66

-45.1%

COB

$38.02

-48.5%

SP 15

$38.31

-51.7%

Palo Verde

$34.77

-51.6%

Minnesota Minnesota 

Hub

$32.09

-52.4%

SPP

$32.94

-52.1%

NP 15

$39.29

-51.0%

Four Corners

$35.38

-50.8%

NI Hub

$34.47

-47.9%

ERCOT

$26.59

-57.6%

Entergy

$33.57

-51.0% Florida

$40.75

-45.4%

Southern

$36.58

-47.8%

TVA

$34.91

-49.4%

PJM West

$44.60

-46.7%

Cinergy

$34.65

-48.2%

NYPP 

Zone J

$55.77

-50.5%

NYPP Zone G

$49.80

-50.7% Mass Hub

$46.24

-49.5%

Source: Derived from Platts data.

With lower electricity demand and lower fuel costs, electricity prices fell by half.  In the 

New York ISO and ISO‐New England, the average electricity price in 2009 was the 

lowest since the markets began in their current form (NYISO in 1999, ISO‐NE in 2003). 

The majority of the drop in prices is attributable to the drastic declines in fuel prices. In 

addition to lower natural gas prices, spot coal prices declined by over 40% in the East 

and #2 fuel oil was down 42% in New York.  In wholesale electric markets, lower fuel 

costs translated to lower prices.

But even absent the steep drop in fuel, the effects of the recession would likely have 

lowered electric prices.  For example, Monitoring Analytics reported in its 2009 PJM 

State of the Markets Report that fuel adjusted prices fell 10% from 2008 as a result of 

lower demand. 
8

Gas and Coal Moved Gas and Coal Moved 

Closer to Parity Closer to Parity

Operating Margin ($/MWh)

0

20

40

60

80

100

120

Gas Unit

Coal Unit

JAN

07

APR

07

JUL

07

OCT

07

JAN

08

APR

08

JUL

08

OCT

08

JAN

09

APR

09

JUL

09

OCT

09 Source: Derived from 

Bloomberg data.

As fuel prices fell during 2009, the traditional price relationships among the leading 

fossil fuels became more malleable.  Fuel oil prices separated from gas prices, moving 

at one time to more than seven times as much on a Btu basis.  The spread narrowed for 

the winter but has returned to last fall’s levels.

We noted in last year’s report that lower gas prices were pushing coal plants up the 

dispatch stack in parts of the country.  This change meant that natural gas sales to 

power plants increased as more gas fired plants moved to baseload service.  During the 

year, gas demand for power generation increased 5 percent, even as electric demand 

fell.  This demand growth was particularly pronounced in the Southeast where gas 

burn in power plants averaged 4.2 Bcfd, up 14% from 2008.  

The change in the relationship of gas and coal, coupled with the reduced demand for 

power, likely contributed to the reduction of NOx and SOx emissions which fell 30 and 

25 percent, respectively, during the year, according to the EPA. These changes also 

squeezed spark spreads and dark spreads, a measure of coal‐ and gas‐fired plant 

operating margins after accounting for fuel costs.  Monitoring Analytics estimates that 

PJM’s coal plants’ margins fell by three‐quarters of their after‐fuel revenues while 

combined cycle gas plants’ margins fell less than one‐quarter between 2008 and 2009.
9

Gas and Wind Dominate Gas and Wind Dominate 

2009 Generation Additions 2009 Generation Additions

*Note: Other includes solar, other renewables, and waste heat.

Nameplate Capacity (MW)

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Gas

NPCC

RFC

SERC

FRCC

SPP

ERCOT

MRO

WECC

Wind Coal Other* Oil Hydro Source: Derived from 

Energy Velocity data.

About 25 GW of new generating capacity was put into service in 2009.   For the second 

consecutive year, gas and wind led the additions, accounting for 84 percent of the new 

capacity.  

The advent of the recession may have had a small effect on the amount of capacity 

coming on line during the year; most plants put into service last year would have been 

too far along to stop construction. The amount of generation capacity coming online 

during the year was down 5% from 2008.  Industry reports indicate that 82 GW of 

capacity has been cancelled or postponed since the beginning of the recession.  This 

rate was not out of the norm compared to recent years. 

About one‐quarter of the cancelled plants were wind generators.  However, plans for 

several new wind generators are still going forward, a possible result of the prepaid 

tax credits in the American Recovery & Reinvestment Act (ARRA) that cover 30 

percent of construction costs for wind, solar, geothermal and other innovative energy 

projects.  In the second half of 2009, 37 large wind generation facilities received $1.9 

billion under this program.  Going forward, even with the announced cancellations, 

another 85 GW of new wind capacity has been proposed  to be online by the end of 

2012.
10

Natural Gas Production Natural Gas Production 

Up Despite Fewer Rigs Up Despite Fewer Rigs

Weekly Average Rig Count and Marketed Production

Bcfd

46

48

50

52

54

56

58

60

62

64

0

200

400

600

800

1000

1200

1400

1600

1800 Rig Count

Marketed Production

Rig Count

JAN

08

APR

08

AUG

08

FEB

10

DEC

08

MAR

09

JUL

09

NOV

09

Source: Derived 

from Baker 

Hughes and 

Bentek

In contrast to 2008 when the commodity bubble, Gulf Coast hurricanes and the advent of 

the recession buffeted the gas market, 2009 provided clarity on gas supply.  Even as 

prices and drilling were dropping from record highs, domestic gas production 

remained strong.  The strength stems from technological innovation in producing gas 

from shale in Texas, Louisiana, Oklahoma, Arkansas and Pennsylvania. Production 

from these new sources is also creating a subtle shift in the market as supply activity 

increases onshore in northern Texas and Louisiana at places such as near Perryville, 

Louisiana, and decreases in and around the Gulf at places such as Henry Hub.

Not that long ago, it would take several months from the start of drilling to initial 

production.  Average‐time‐to‐drill in 2009 was about 20 days. Nowadays, production is 

almost certain before drilling begins, and well efficiency increases as producers learn 

the particular nuances of a given play. Because shale production has many of the 

characteristics of gas in storage, companies have greater flexibility to produce gas 

when the market calls for it. Production can be deferred without risking the integrity of 

the well.  Ending long production lead times and the risk of failure or loss may 

dramatically temper the gas market’s systemic boom‐and‐bust cycle.

Continued on Next Page
11

Continued From Previous Page

New storage capacity may be expected to complement this trend.  More than 107 Bcf of 

incremental working gas capacity was added in 2009, including more than 50 Bcf in 

the Gulf region.  Additional production area storage, in particular, allows suppliers to 

respond more adeptly to market signals, and as a result, those signals are 

moderated. EIA says that U.S. peak working gas capacity is around 3,900 Bcf. In late 

November 2009, U.S. inventories were 99% of capacity.
12

U.S. Natural Gas Resource U.S. Natural Gas Resource 

Estimates Growing Estimates Growing

-

500

1,000

1,500

2,000

2,500

Shell

1977

Hubbert

1980

Rand

1981

USGS

1981

PGC

1983

USGS

1999

PGC

2006

PGC

2008

Trillion Cubic Feet

Source: Potential 

Gas Committee, 

Rand Corporation, 

U.S. Geological 

Survey, Royal Dutch 

Shell Co, and 

Hubbert

A key distinguishing characteristic of last year’s gas supply rally is that it appears to be 

sustainable.  In June 2009, the Potential Gas Committee, an independent group that 

develops assessments of gas resources, raised its estimate to over 2 quadrillion cubic 

feet, almost 100 years of gas supply at current consumption levels.  The large increase 

is almost entirely due to improvements in our ability to produce gas from shale with 

certainty and control.  

There is concern about the possible environmental effects of shale production.  In 

March, in response to a congressional request, the EPA announced that it would spend 

$1.9 million to conduct a transparent, peer‐reviewed study to answer questions about 

the potential impact of hydraulic fracturing on human health and the environment.  

This study is expected to address potential groundwater and air pollution concerns.
13

Source: Derived 

from ICE data.

-10

-8

-6

-4

-2

0

2

4

6

8

10

$/MMBtu

JAN

07

APR

07

JUL

07

OCT

07

JAN

08

APR

08

JUL

08

OCT

08

JAN

09

APR

09

JUL

09

OCT

09

JAN

10

Opal

AGT

Panhandle

New Infrastructure Created New Infrastructure Created 

National Gas Market National Gas Market

Tetco M3

In addition to the advances in gas supply that may be reducing the cyclical nature of 

the natural gas market, 2009 brought important expansions and extensions of gas 

transmission capacity that will reduce volatility in the price of gas delivered to market.  

The largest change in the physical infrastructure of the gas market came with the 

completion of the Rockies Express Pipeline from Wyoming to Eastern Ohio.  REX 

serves the dual role of relieving the constraints that suppressed prices in the West 

while, at the same time, relieving the constraints that increased  prices in the East.  

Other, smaller, projects have had similar effects.  New pipelines to increase the flow of 

Barnett shale gas into the interstate network have had the secondary effect of reducing 

congestion across the Texas‐Louisiana border, a remnant of the pre‐1978 days of strict 

delineation between inter‐ and intrastate supplies.  The United States is closer than 

ever before to being a single natural gas market with congestion limited to a few 

markets for a few periods during the year.  This chart shows that the price difference 

from Henry Hub at places as diverse as New England, western Wyoming, the Mid‐

Atlantic and North Texas are coming closer together and that, when they do diverge, 

the divergence is much less than in the past.

Continued on Next Page
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Continued From Previous Page

The Florida peninsula and Northern California now seem to be the most frequently 

constrained parts of the country, but each is slated to receive significant new pipeline 

capacity next year.  In November 2009, the Commission issued a certificate to the 

Phase VIII expansion of Florida Gas Transmission which is slated to add about 800 

MMcfd of gas transmission capacity to peninsular Florida.  Additionally, this month, the 

Commission authorized construction of 1,500 MMcfd Ruby Pipeline from Opal, 

Wyoming to Malin, Oregon.  Both pipelines are expected to be in service in the Spring 

of 2011.
15

Sendout Sendout Increased from North Increased from North 

Atlantic LNG Terminals Atlantic LNG Terminals

Source: Derived 

from Bentek data.

0

200

400

600

800

1000

1200

1400

1600

MMcfd

Everett Everett

NE Gateway

Canaport Canaport

JAN

09

F

09

M

09

A

09

M

09

J

09

J

09

JAN

10

D

09

A

09

S

09

O

09

N

09

F

10

M

10

In addition to increased gas production in the mid‐Atlantic area and expanded pipeline 

and storage capacity, new market area Liquefied Natural Gas import capacity appears 

to have reduced winter price volatility in New England.  Over the course of 2009, 2 

Bcfd of sendout capacity was added at the Northeast Gateway terminal in 

Massachusetts Bay and the Canaport terminal in St. John, New Brunswick.  A fourth 

terminal, Neptune, off the northern coast of Massachusetts, began operation with a 

possible additional sendout of 750 MMcfd.

During the course of this winter, there were days when these terminals as well as the 

Everett terminal near Boston accounted for half of New England’s gas supplies. On 

those days—days nearing all‐time natural gas demand peaks in the Northeast—the 

basis from Henry Hub never exceeded $5.25 MMBtu.  In the past, gas commonly 

reached a premium of $10‐15 per MMBtu on peak days.

In contrast to the New England terminals, Gulf Coast LNG terminals such as Sabine 

Pass and Freeport last year sought authorization to re‐export gas supplies elsewhere.
16

RTO Market Events RTO Market Events

 MISO

• Ancillary Services Market (ASM) begins

• Balancing area consolidated

• Three Iowa utilities join

 SPP

• Integration of Nebraska entities and 

Missouri Public Service

Last year, on January 6, the Midwest ISO began its new Ancillary Services Market at the 

same time it consolidated its operations into a single balancing authority area.  The 

consolidated procurement of reserves with energy across the entire market yielded 

reliability and efficiency benefits and, it appears, lower price volatility. 

Also in MISO, three Iowa utilities, Mid‐American Energy Company, Muscatine Power 

and Water, and the Municipal Electric Utility of Cedar Falls integrated into MISO on 

September 1, bringing to the market over 4,000 MW of load and 7,500 MW of 

generation. Mid‐American, alone, brought 1,500 MW of wind resources on the 

expectation that the renewable generation could be more efficiently used across the 

wider market footprint. The addition of the Iowa utilities did change congestion 

patterns in and around Iowa, but these changes were all manageable.

The integration of Nebraska utilities and Missouri Public Service into SPP’s Energy 

Imbalance Service market added lower cost coal and nuclear generation to the RTO.  

Limited available transmission capability within the SPP footprint, north to south, 

resulted in frequent visible congestion and price separation in the market. SPP has 

approved several transmission projects that are intended to reduce congestion and 

bring down prices throughout the entire footprint; those projects are scheduled to be 

completed by 2013.
17

CAISO Initiated its New CAISO Initiated its New 

Nodal Market on April 1 Nodal Market on April 1

The biggest RTO development of the year was the long‐awaited initiation of CAISO’s

new market on March 31.  Since the market started, prices have been generally 

consistent with nation‐wide trends, though CAISO experienced some early start‐up 

issues. 

During the first few months of the new market, energy price volatility in the real‐time 

market lead to some extreme price outcomes, principally during the morning ramp 

hours in Southern California.  On April 19, for example, San Diego experienced very 

high 5 minute prices caused by the dispatch of distant generators to solve a 

transmission constraint.  Lack of flexibility in dispatching reserves in San Diego also 

contributed to this situation.

The California ISO addressed that problem and similar ones by moving in the direction 

of greater transparency, adapting and relying increasingly on the results of the market 

model and less on devices outside the model run such as exceptional dispatch and 

manually managed transmission constraints.  This allows market participants to better 

understand the system as more of the market operations are reflected in locational

prices and less is reflected in uplift and other out‐of‐market add‐ons.

Continued on Next Page
18

Continued From Previous Page

From the start of the market, over the course of 2009, average Day‐Ahead Market 

locational prices of wholesale electricity in the California ISO fell into a relatively tight 

band across the state.  Prices were highest in Northwest California and lowest at in‐

state hydro facilities in the mountains.

A major component in the difference in prices is the cost of congestion.  This 

congestion component is what a financial transmission right (FTR), or in CAISO’s case 

a congestion revenue right (CRR), is designed to hedge against.
19

Congestion Fell Below Congestion Fell Below 

Expectations Expectations

Source: Derived from 

Ventyx and non-public 

allocation data from 

individual RTOs

(excluding CAISO).

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

Dollars (millions)

Allocations

Financial Financial

Hybrid

Physical Physical

CAISO ISO-NE

PJM

NYISO MISO

2008-2009 Net Auction Value (NAV ) and Day-Ahead

Congestion Congestion Value (DA CV ) by Participant ) by Participant

One key impact of the recession has been a decline in the cost of congestion in the 

RTOs.  RTOs allocate congestion revenues through instruments commonly known as 

financial transmission rights (FTRs), but they are also known, more descriptively, as 

congestion revenue rights (CRRs) in California and Transmission Congestion Contracts 

(TCCs) in New York.  FTRs determine the net amount of FTRs based on the physical 

structure of the transmission system.  Because the payout for an FTR comes from the 

cost of congestion over a path, the value of an FTR represents an expectation of that 

congestion costs or, in the case of a hedge, the value of eliminating the risk associated 

with market results.  

It is not easy to compare congestion consistently across markets.  Each RTO’s

Commission‐approved tariff provides unique rules for how the congestion revenues 

and rights are allocated and/or sold. This analysis of congestion costs has delved into 

this painstaking detail because it is important to understand the role they play in the 

RTOs.

Continued on Next Page
20

Continued From Previous Page

In each of the RTO markets, the cost of congestion fell below expectations as expressed 

in the RTOs’ FTR markets.  While congestion costs in the largest market, PJM, fell by a 

quarter, the largest drop in percentage terms was in ISO‐NE, where falling demand and 

fuel prices were complemented by transmission additions that reduced congestion.

Much of the change in congestion costs was related to the congestion rights allocated to 

physical participants that account for over two‐thirds the net value in the FTR market.  

These allocated rights are typically given to load serving entities to be used as hedges 

against congestion. This means the changing market value of the rights have little 

effect.  In the market for purchased FTRs, purely financial players, participants who 

have no discernable physical position in the market, made approximately $3 million in 

net revenues on the change in congestion costs in 2009 primarily because congestion 

increases in MISO offset losses in PJM and ISO‐NE.
21

Summary Summary

 Demand down for the year, but with 

hopeful signs of recovery

 New gas paradigm emerged

 Gas and wind led generation capacity 

additions

 Flexibility assisted the start of the new 

California market

 Congestion costs fell

In summary, while 2009 did not resemble 2008’s rollercoaster ride, it was not boring.  

Gas, coal and electricity prices fell, and demand was off for the year.

A new gas world came into sharper focus with technological innovation possibly 

changing the paradigm for the gas market; the EPA will be studying the environmental 

implications of new production methods in new areas.

Almost 25 GW of new generation was added during the year, with natural gas and wind 

leading the way. 

The California ISO embarked on a new market with enough flexibility to respond to 

start‐up issues that arose; and

The cost of congestion fell in the RTOs as prices and demand fell.
22

Item No: A-3

April 15, 2010

Federal Energy Regulatory Commission

State of the Markets State of the Markets

Report 2009 Report 2009