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Item No: A-3

April 21, 2011 April 21, 2011

FEDERAL ENERGY REGULATORY COMMISSION

2010

State of the Markets State of the Markets

Good morning Mr. Chairman and Commissioners.

We are pleased to present the Office of Enforcement’s 2010 State of the Markets report. The 

State of the Markets is staff’s annual opportunity to share observations about natural gas, electric 

and other energy markets.

Before we begin, I’d like to mention that this presentation is based on opinions and conclusions of 

staff and not necessarily those of the Commission, the Chairman, or any of the individual 

Commissioners.
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State of the Markets State of the Markets

2010

 Natural gas supply and demand reached 

record highs, while gas prices remained 

moderate throughout the year

 Pipelines adjust to new shale gas production

 Electric demand increased

 Electric capacity additions slowed

In 2010 we saw natural gas supply and demand set new records, while natural gas prices remained 

moderate through most of the year. We also saw regional changes in natural gas production and 

new infrastructure changing utilization along some key pipeline routes across the country. There 

was also increased demand in the power sector, but a decrease in the amount of power 

generation capacity added compared to prior years. Specifically, wind and natural gas-fired 

generation additions dropped off in 2010.
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Henry Hub Natural Gas Henry Hub Natural Gas 

Daily Spot Price Daily Spot Price

Source: Intercontinental Exchange

0

2

4

6

8

10

12

14

16

J FM AMJ J A S ON D

'04-'08 Range 2009 2010

Though 2010 natural gas prices were up about 12 percent on average over 2009, they remained 

well below the levels of previous years. Natural gas demand increased in 2010 and was only 

partially offset by increased natural gas supply. Natural gas storage levels were high for much of 

the year and reached record levels in November. Outside of early winter 2010 and a few days in 

June, spot prices at the Henry Hub remained between $3/MMBtu and $5/MMBtu. By the end of 

the year, prices remained low despite a cold start to the winter.
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Natural Gas Prices Natural Gas Prices 

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

Source: Intercontinental Exchange

Sumas

$4.10

9%

SoCal

$4.27

16%

AECO

$3.88

PG&E 11%

$4.53

10%

Opal

$3.93

26%

Panhandle Panhandle 

$4.14

27%

HSC

$4.33

15%

Henry

$4.37

12%

Chicago

$4.45

13%

TCO

$4.52

10%

TZ6 NY

$5.39

10%

FGT Z3

$4.41

11%

As at Henry Hub, average spot natural gas prices rose across the country. In last year’s State of 

the Markets presentation, we highlighted the development of a national gas market due to 

increases in domestic production, added pipeline infrastructure and increased storage capacity. 

This trend continued in 2010, with regional price differences increasingly reflecting the variable 

cost of transport between hubs. Prices in the Rockies and Lower Midcontinent producing regions 

rose closer to the Henry Hub in 2010 as increased takeaway capacity to higher priced markets 

lifted local prices. The difference between natural gas prices in the Northeast and the Henry Hub 

fell as increased local production and pipeline capacity gave the Northeast more options to obtain 

natural gas. 
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Natural Gas Prices vs. Natural Gas Prices vs. 

Other Commodity Prices Other Commodity Prices

Source: Bloomberg

0

200

400

600

800

1000

Index (1970=100)

0

2

4

6

8

10

12

14

16

$/MMBtu

GSCI

Natural Natural Gas

Coal

2007 2008 2009 2010

The course of natural gas prices in 2010 revealed an interesting new market dynamic. Through 

recent years, natural gas prices moved together with other commodities, represented here by the 

Goldman Sachs Commodity Index (GSCI). Yet even though the GSCI has doubled in the last two 

years, natural gas prices have remained relatively flat. This is a result of several factors. Aside 

from a small amount of LNG imports, at present, the North American natural gas market is self 

sufficient and largely insulated from the international pressures that other commodities face. 

Strong domestic production growth, combined with added pipeline and storage infrastructure, 

have increased domestic supply and reduced geographic and seasonal price differences. And 

unlike in 2008, natural gas prices appear to be responding primarily to physical fundamentals, 

namely growing supply from lower-cost sources, rather than financial market influences. Also, 

the graph shows that natural gas prices and coal prices have been converging. This has led to 

some dispatching of natural gas-fired generation before coal-fired generation.
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Natural Gas Demand Natural Gas Demand 

Grows in 2010 Grows in 2010

Source: Bentek Energy

Average Daily Natural Gas Demand ( Average Daily Natural Gas Demand (Bcf/d)

0

5

10

15

20

25

Power Industrial Residential

Commercial Other

2009

2010

8.6% 4.0% 0.6%

2.4%

Following several years of modest growth, U.S. natural gas demand increased 3.7 percent in 2010. 

This was driven by a recovering economy that boosted industrial natural gas demand by 4 percent 

and by strong growth in the power sector. There was virtually no growth in residential and 

commercial consumption.

Though weather conditions can affect year-to-year demand in the power sector, the use of 

natural gas to generate electricity has grown steadily in recent years and now accounts for almost 

one-third of total U.S. natural gas demand. Increased natural gas generating capacity utilization, 

the large growth in and lower production cost of proven natural gas reserves and a flatter forward 

curve have positioned natural gas generation to increase market share in the power sector. 

Natural gas is increasingly edging out coal as the most economical fuel for baseload power 

production in more parts of the country for longer periods during the year. This added 

approximately 1.1 Bcf/d to 2.8 Bcf/d on average to total U.S. natural gas demand over the course 

of 2010. Given current natural gas and coal prices this trend should continue in 2011.
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Gas Production Gas Production 

Continues to Grow Continues to Grow

Source: Bentek Energy

0

20

40

60

80

2001 2003 2005 2007 2009 2011 2013 2015

Production (Bcf/d)

-5%

5%

15%

25%

35%

Shale Production as % of Total

Nonshale

Shale

% Shale Projected

U.S. domestic natural gas production grew steadily over the course of the year, from just over 58 

Bcf/d in early January to more than 63 Bcf/d in late December, reaching record highs. This 

growth can be attributed to increased shale-gas production, which accounted for 23 percent of 

total U.S. production by the end of 2010, up from just 13 percent of total production two years 

before. Production from the Haynesville, Fayetteville and Marcellus basins alone grew more than 

7 Bcf/d in the four years from January 2007 to January 2011. Some market analysts forecast 

shale-gas could account for one-third of total U.S. production by the end of 2015. 

This production growth occurred in spite of continued low natural gas prices because much of the 

increase in natural gas production in 2010 was associated with natural gas liquids (NGL). Natural 

gas liquids include ethane, propane, butane and natural gasoline and can add a significant source 

of revenue to natural gas production, particularly because NGL prices have been increasing with 

the oil market. In some plays such as the Eagle Ford and North Barnett Shale in Texas, and the 

Bakken Field in the Dakotas, the breakeven cost for natural gas has fallen to zero, and natural gas 

has essentially become a byproduct of oil and NGL drilling. With this trend, we witnessed a shift 

in drilling from pure natural gas wells to wells that produce both natural gas and NGLs.

Over 2010, there were renewed environmental concerns regarding air and water quality problems 

associated with both the increased level and methods involved with natural gas extraction, 

specifically the hydraulic fracturing method used in shale-gas drilling. The Environmental 

Protection Agency, at the direction of Congress, is undertaking “a study of this practice to better 

understand any potential impacts of hydraulic fracturing on drinking water and groundwater.”

The EPA recently submitted its draft study plan to the agency’s Science Advisory Board, with the 

goal of understanding the relationship between hydraulic fracturing and drinking water resources 

from the beginning to the end of the drilling cycle, and expects initial research results by the end 

of 2012 and a final report in 2014.

Continued on next page
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Continued from previous page

Another aspect of the growth in onshore shale-gas is that the U.S. is less susceptible to disruptions 

in production from hurricanes in the Gulf of Mexico. However, we have seen instances of well 

freeze-offs that can have a significant though short-lived effect on onshore production.
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Shale Growth Affects Shale Growth Affects 

Pipeline Utilization Pipeline Utilization

Source: Bentek Energy

Variable

Transportation 

Cost at $4/MMBtu 

2010 Year over 

Year Change 

in Flows as %

$0.42

From Rockies

From Western Canada

From SE/Gulf

-25%

$0.32 +60%

$0.35 -8%

Production

$0.23 +35%

Regional changes in natural gas production and new long-haul pipelines are changing utilization 

along some key pipeline routes across the country. The 1.87 Bcf/d Rockies Express Pipeline, 

which completed its route from Wyoming to Ohio in 2010, displaced natural gas from Western 

Canada and to a lesser extent the Gulf Coast. That displacement has accelerated with the rapid 

growth of Marcellus natural gas production. U.S. natural gas is now being regularly exported to 

Canada via backhaul and a number of proposed new Northeast pipeline projects will export 

Marcellus natural gas to Canada. 

Pipelines at most risk for displacement include those flowing Canadian, Midcontinent and Gulf 

Coast production to the Northeast.

In Canada, TransCanada filed for a reduction in its long-haul rates to try to keep long-haul 

customers, proposing to make up for lost revenues by increasing rates on short-haul customers. In 

the United States, both Columbia Gulf and Tennessee filed rate increase proposals, citing growing 

Marcellus production and a need to offer discounts on long-haul rates from the Gulf Coast to 

compete. These pipelines will likely see less utilization on pipeline segments between the Gulf 

Coast, the Midcontinent and the Northeast but will likely have higher short-haul utilization within 

the Northeast.

This is a trend we will be following as regional shifts in natural gas production continue to impact 

pipeline utilization on established long-haul pipelines with higher transportation costs.
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FERC Order No. 720 FERC Order No. 720

Improves Market Transparency Improves Market Transparency

Source: Bentek Energy

0

10

20

30

40

50

60

70

Supply (Bcf)

Interstate Interstate Pipelines Pipelines

Non-Interstate Pipelines

U.S. Supply Estimate

J FM AMJ J A S ON D

FERC Order No. 720, implemented on October 1, 2010, required major non-interstate pipelines to 

begin posting daily nominated receipts and deliveries on their systems. The result was a sharp 

increase in market transparency. Prior to October 1, 65 percent of U.S. natural gas supply was 

visible to the market. After October 1 this increased to 95 percent, and we now know that 

intrastate pipelines account for approximately 18 Bcf/d of daily U.S. natural gas supply. This 

allows the market to estimate daily U.S. natural gas supply much more accurately. In Texas, 

observable production increased from 5 Bcf/d in the first half of 2010 to more than 17 Bcf/d after 

implementation of Order No. 720. We also observed more deliveries to power plants and 

industrial customers. Order No. 720 has successfully increased market transparency and the level 

of daily market information available to market participants, analysts and regulators.

I will now hand the presentation over to Lance Hinrichs to talk about developments in the electric 

markets. 
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Wholesale Electricity Wholesale Electricity 

Prices Increased Prices Increased

Source: Platts

Mid-Columbia

$35.90

.7%

Palo Verde

$38.76

12%

Minnesota Minnesota 

Hub

$36.86

15%

NI Hub

$40.85

19%

Mass Hub

$56.18

22%

NP 15

$40.08

2%

SP 15

$40.21

5%

Florida

$50.18

25%

ERCOT

$41.15

18%

SPP

$38.71

18%

Entergy

$40.07

19%

Southern

$42.61

17%

NYPP 

Zone J

$65.76

18%

Cinergy

$41.51

20%

PJM West

$53.68

20%

Last year we reported that 2009 wholesale electricity prices fell by half from the previous year. 

In contrast, 2010 peak hour prices were up almost 17 percent compared to 2009. Despite this 

increase, 2010 prices are still roughly 42 percent lower than 2008.

The 2010 price rise was primarily related to the previously mentioned increase in fuel price. 

However, higher power loads throughout most of the country also had an impact; making it 

necessary for operators to rely on higher cost generators. 

As this map shows, the increase in price was not uniform across the country. In the East, a hot 

summer, along with early signs of a moderate economic recovery, pushed up electricity demand. 

In PJM, for example, average load was up 4.7 percent. Overall, Eastern prices rose by nearly 20 

percent.

In contrast, the West experienced a more modest increase in prices due to mild weather. 

Specifically, a relatively mild summer in California led to a decrease in load of almost 3 percent, 

compared to 2009. Late spring precipitation in the Northwest resulted in better than expected 

hydro generation output which also moderated prices and even resulted in negative off-peak 

prices, at the Mid-Columbia trading hub. Overall, prices in the West were up by 6 percent.
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Industrial Consumption Industrial Consumption 

Bolstered by Improving Bolstered by Improving 

Economy Economy

Source: U.S. Energy Information Administration, Electric Power Monthly, March 11, 2011

800

850

900

950

1000

1050

2002 2004 2006 2008 2010

GWh x 1000

Consumption of electricity increased in 2010, in part, due to the improving economy. The 

recession helped to drive down consumption, from a high in 2007 to a low in 2009, and in 2010 we 

saw the initial signs of a recovery. Even though industrial demand has not returned to the earlier 

levels, it is consistent with the economy’s 2.9 percent rise in gross domestic product in 2010.

Not shown on this chart are the consumption trends for the residential sector, which are primarily 

driven by weather. After a relatively mild 2009, residential usage was up by 6 percent in 2010. In 

particular, the summer months were hotter than normal for all regions but the Pacific Coast 

states. In the Sunbelt, there was record heat and, as a result, the Southwest Power Pool and 

ERCOT set records for peak electric demand. Additionally, the winter months produced more 

heating degree days than normal in all sections of the country except for New England and the 

western states. 
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Capacity Additions Drop Capacity Additions Drop

Source: Energy Velocity

0

5

10

15

20

25

2006 2007 2008 2009 2010

Gas

Wind

Nuclear Nuclear

Other

MW x 1000

Coal

Solar

In 2010, we saw a drop in the amount of new electric generation capacity added compared to the 

prior year. Overall, plant additions were down approximately 20 percent in 2010, compared to 

2009. This is consistent with the effects of a slowly recovering economy, sluggish power demand 

growth and tight credit in recent years.

While natural gas and wind plants have recently dominated the megawatt-capacity share of 

additions, there was an increase in the amount of new coal-fired generation in 2010. These new 

coal plants came from projects that were the product of a multi-year development process that 

was initiated when the economic signals for investment were quite different from today. Over 

the past four years, the relative fuel cost advantage for coal plants has decreased, coinciding with 

the previously mentioned increases in shale gas production. In contrast, the development 

timeline for natural gas and wind plants is appreciably shorter.

High capital cost, reduced load growth and plentiful natural gas supplies have slowed the 

development of new nuclear facilities. Over the last several years, the NRC received 19 

applications to either construct or reserve sites for new plants. However, by the end of 2010, 

several of the developers requested that the NRC suspend review of their applications, and others 

have indicated that they will not immediately proceed with construction. Utilities in traditional 

markets are developing most of the nuclear plants that are still moving forward. In particular, 

the Southern Company and SCANA have started preliminary site work for new reactors at two 

different sites.
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Renewable Generation Renewable Generation 

Sees Shift in Growth Sees Shift in Growth

Source: Energy Velocity, Interstate Renewable Energy Council and Department of Energy MW in thousands MW in thousands

0

2

4

6

8

10

2006 2007 2008 2009 2010

Solar

Wind

Renewable resource additions in 2010 were mixed.

For renewable capacity, wind was the leader, adding just over 5,000 MW. Despite a 15 percent 

drop in turbine prices and a continuation of federal tax incentives, this growth was roughly half 

the rate of the previous two years. It was primarily attributable to significantly lower natural gas 

prices and a weak investment environment. These conditions made it difficult for developers to 

sign long-term power-purchase agreements, which are an important consideration to project 

financing. 

The Midwest ISO added the most wind generation, with an additional 1,500 MW, now bringing its 

system-wide capacity to more than 9,000 MW. This now rivals ERCOT as the region with the 

greatest wind capacity. The system-wide share of wind grew to between 4 and 8 percent of total 

energy output in MISO, SPP, and ERCOT.

Solar projects grew robustly in 2010. Grid-connected solar photovoltaics increased at twice the 

rate of 2009, adding 883 MW. Five states dominated these additions: California, New Jersey, 

Nevada, Arizona, and Colorado, which together accounted for 64 percent of the new capacity. 

Separately, concentrating thermal solar power grew by 77 MW, the first big jump since the 1980s. 

In total, there is now more than 2,000 MW of grid-connected solar capacity.

This growth has been supported by several factors, which include state-level incentives, favorable 

federal tax policies and a 21 percent decline in system costs. In particular, 16 states and 

Washington D.C. have provisions in renewable portfolio or energy standards that specify what 

percent of their target should be solar generation or distributed resources. Also, utilities tripled 

their photovoltaic installations to 242 MW, as they capitalized on changes that allow them to use 

federal tax credits and cash grants.

Continued on next page
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Continued from previous page

In response to the growth in renewables and their role in the markets, the 

Commission issued a Notice of Proposed Rulemaking for Variable Energy Resources 

in Docket No. RM10-11-000. In it, the Commission sought comments on the extent 

to which barriers may exist that impede the reliable and efficient integration of 

variable energy resources into the grid, and whether reforms are needed to 

eliminate those barriers.
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Capacity Markets Supported Capacity Markets Supported 

by Demand Response by Demand Response

Source: PJM and ISO-NE data

Demand Resources Generation

0

1,000

3,000

5,000

7,000

Megawatts

0

200

400

600

Megawatts

2012/13

2012/13 2013/14

2013/14

PJM ISO-NE

RTO capacity markets provide a means for load-serving entities to procure resources to meet 

forecast load and allow generators to recover a portion of their fixed costs. In PJM and ISO-NE, 

capacity commitments are for a three-year period into the future. NYISO conducts capacity 

auctions for the upcoming season in the form of semi-annual seasonal strip auctions.

Despite a modest capacity price increase for PJM in 2010, the prices for the forward delivery 

years of 2012-13 and 2013-14 have generally been steady or decreasing for both PJM and New

England. Forecasted load growth rates for both PJM and ISO-NE, a key input for determining when 

new capacity will be needed, have remained relatively flat or declined, reflecting modest 

economic growth. In the auctions conducted last year for the forward delivery period of 2013-

2014, PJM’s RTO-wide price was $843 per MW-month, with locational prices higher in the eastern 

part of the region. This was up 68 percent from the auction for the 2012-2013 delivery year, but 

down 75 percent from the auction conducted the year prior. ISO-NE’s price was $2,951 per MWmonth, unchanged from the 2009 auction for the 2012-2013 delivery year.

For the auctions held in 2010, demand resources, that is demand response and energy efficiency, 

accounted for much of the incremental capacity for the forward periods. In PJM, net of 

retirements or deratings, 60 percent of new, incremental capacity committed was associated with 

demand response. In New England, 96 percent of the new capacity commitments were also 

associated with demand resources.

Continued on next page
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Continued from previous page

Turning to New York, the summer peak load forecast for the state was down 450 

MW or approximately 1 percent less than the previous year. Further, in 2010, 

NYISO saw a 900 MW net increase in capacity resources over the 2009 level. That, 

combined with a 130 MW increase in demand response, resulted in a slight 

decrease in capacity prices for 2010, when compared to 2009. Summer strip 

prices for New York State were $2,470 per MW-month, down 18 percent compared 

to the prior summer.

New York City, a notable load pocket, had a large generator discontinue 

operations, and capacity prices for the summer capability period increased, as 

anticipated. Demand-response resources in the city remained important to the 

supply-demand equation, with more than 480 MW of demand response capacity 

offered at auction, which is about 20 percent of all demand-response resources in 

the NYISO.
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RTO Market Rule and RTO Market Rule and 

Design Changes Design Changes

 SPP’s Integrated Transmission Plan 

(ITP) approved

 CAISO new category for policy-driven 

transmission approved

 ERCOT commences its nodal market

Last year, the Commission approved a number of RTO market rule changes on topics ranging from 

transmission planning and cost allocation to capacity market mitigation measures. For example, the 

Commission approved SPP’s Integrated Transmission Plan (ITP) where SPP conducts 20-year, 10-year and 

near-term assessments to determine transmission needs particularly for higher-voltage facilities. The 

Commission also approved the CAISO’s tariff proposal to create a new category of policy-driven transmission 

facilities to meet policy requirements and directives. 

In Texas, ERCOT launched its nodal market redesign on December 1st. This market is, of course, not 

regulated by the Commission; however their design is similar to several of markets that we oversee and the 

Division of Market Oversight will be following these developments to observe their results. The major 

upgrades to the ERCOT model include a transition from a four-zone pricing model to one with 8,000 nodes 

and, also, the introduction of both a day-ahead market and congestion revenue rights, which are similar to

financial transmission rights, or FTRs. 

That completes our presentation. We are available if you have any questions.
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Item No: A-3

April 21, 2011 April 21, 2011

FEDERAL ENERGY REGULATORY COMMISSION

2010

State of the Markets State of the Markets