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2008

Summer Market and Summer Market and 

Reliability Assessment Reliability Assessment

Item No.: A-3

May 15, 2008 May 15, 2008

Mr. Chairman and Commissioners, good morning. We are here to present the Summer Market and 

Reliability Assessment for 2008. This presentation will be posted on the Commission’s Web site 

today.
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Key Results Key Results

 The electric system should be The electric system should be 

reliable this summer, with some reliable this summer, with some 

local issues local issues

 Electric prices likely to rise Electric prices likely to rise

 Gas infrastructure supports Gas infrastructure supports 

growing electric markets growing electric markets

Today, we will emphasize three main points:

1. Overall the reliability of the bulk power system for this summer should be adequate. But there are 

some areas of concern that require close monitoring.

2. Wholesale electric prices are likely to be considerably higher than they were a 

year ago.

3. In the fastest growing regions – Florida and Arizona, for example – the continuing robustness of 

the natural gas infrastructure plays a crucial role in meeting growing electric power demand. 
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National Reliability National Reliability 

Issues

 Overall Reliability Assessment Overall Reliability Assessment

 Demand Forecast Demand Forecast

 Capacity Margins Capacity Margins

 Demand Response Demand Response

 New Generation New Generation 

 Regional Highlights Regional Highlights

The reliability and adequacy of the bulk power system this summer, as forecasted by the planning 

authorities and reviewed by the Regional Entities and NERC is projected to be adequate. Extreme 

weather conditions and major outages of generation and transmission pose risks to reliability and 

where these risks are significant, contingency plans, including operating procedures, are expected to 

be in place to manage these risks. 

Overall non-coincident peak demand this summer, assuming normal weather and 50% load forecast 

probability, is forecasted to be 1.3% higher than the actual demands of last summer with some 

regions showing an increase in demand while others a reduction. While the capacity margins to 

supply this increased demand are forecasted to be sufficient, there are concerns for supply reliability 

due to deliverability of reserves. In particular, these concerns manifest themselves in Southern 

California due to constraints on imports from the north and outside California, and in the Southeast 

should the drought conditions persist, coupled with any major transmission and/or generation 

outages. 

Demand response has increased both as a means to reduce peak demand and to provide ancillary 

services for operating flexibility. 

These issues and regional highlights will be explored in the remainder of the presentation.
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Demand and Capacity Demand and Capacity 

Margin, 2007 Margin, 2007-2008

*WECC

*MRO *NPCC

SERC SPP

ERCOT

FRCC

RFC

∆Demand = 2.8%

Cap M = 19.8%

∆CM = -0.7%

∆Demand = 0.9% 

Cap M = 26.3%

∆CM = 10.7%

∆Demand = 4.1%

Cap M = 12.9%

∆CM = 0.9%

∆Demand = -2.8%

Cap M = 16.9%

∆CM = 2.2%

∆Demand = 1.3%

Cap M = 16.8%

∆CM = 0.8%

∆Demand = 2.2%

Cap M = 21.6%

∆CM= 2.1%

∆Demand = 6.9%

Cap M = 14.8%

∆CM = -2.4%

∆Demand = 1.5%

Cap M = 17.1%

*This includes Canada ∆CM = 1.3%

Source: Derived from 

NERC data and Energy 

Velocity 

Comparison of 

2008 vs 2007 

Demand and 

Capacity 

Margin

Demand Forecast

Demand forecasters use generalized assumptions about weather, economic activity and other 

factors. Therefore, predicting abnormal conditions that create record peaks are difficult. 

Overall, the non-coincident peak-demand forecast is 867,525 MW, which represents a 1.3% increase 

from the actual demand of last summer. On this map, which shows 2008 summer forecasts 

compared with 2007 summer actual peak by region, we see that assuming normal conditions, the 

forecast peak demand is expected to grow from a low of 0.9% in SPP to a high of 6.9% in MRO. The 

exception is the SERC region, which is projecting a demand reduction of 2.8%. This bears scrutiny 

as past forecasts for the SERC region have been consistently lower than actual demands for the last 

few years, when all-time peaks have been repeatedly set. 

Capacity Margins

Capacity margins are indicative of the amount of reserve capacity that is available to avert the risk to 

reliability from a number of uncertainties such as load forecasting errors and outages of bulk power 

system equipment among other factors. The map shows the capacity margins and the change in 

projected capacity margins for the coming summer compared with last summer. Because of different 

generation mixes, unit sizes, deliverability and other factors required reserve margins will vary to 

achieve the same reliability performance. In and of themselves, the capacity margins cannot be 

compared across regions. However, the change in capacity margin within a region, relative to 

historically achieved capacity margins, is an appropriate measure of the resource adequacy of the 

same region. On that basis, the capacity margins shown appear to be on par with prior years. 
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Demand Response Demand Response 

2007-2008

Demand 

Response as 

a % of Total 

Internal 

Demand 

Source: Derived from NERC 

data and Energy Velocity

*WECC

*MRO *NPCC

SPP SERC

ERCOT

FRCC

2007 = 2.3%

2008 = 2.5%

2007 = 1.8%

2008 = 1.7%

2007 = 1.7%

2008 = 1.7%

2007 = 2.8%

2008 = 3.1%

2007 = 2.1%

2008 = 3.4%

2007 = 1.7%

2008 = 3.9%

2007 = 3.9%

2008 = 6.1%

2007 = 6.5%

*This includes Canada 2008 = 6.2%

RFC

Demand Response

This summer, demand response resources have increased to manage peak loads across the United 

States. The amount of dispatchable demand response available to reduce peak load is forecast to 

increase significantly in NPCC from just under 2% of internal demand to 4 % and in MRO from 4% to 

6%. This resource can play an important part in reducing the stress on the grid at the time of system 

peak. 

New Generation

Over 10,000 MW of new generating resources have been added to the US power system over the 

past year. Not all of the new capacity will have a direct impact on capacity margins due to issues 

such as deliverability and coincidence of availability during peak demand periods.
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Forward Markets Suggest Forward Markets Suggest 

Higher Electric Prices Higher Electric Prices

Sources: Summer electric forwards data is July-August 2008 data from ICE as of 5/13/08. Actual on-peak data for 2007 are from 

Platts Megawatt Daily. The Henry Hub data is July-August Clearport data from Bloomberg as of 5/13/08.

Southern California (SP-15)

$129.61/MWh +75%

Northwest (Mid C)

$103.24/MWh +66%

PJM Western Hub

$132.90/MWh +65%

New York City

$176.50/MWh +89%

Massachusetts Hub

$129.70/MWh +78% Midwest ISO (Cinergy)

$103.07/MWh +49%

Palo Verde

$130.83/MWh +73% Henry Hub (Gas) Henry Hub (Gas)

$11.59/MMBtu +86%

The most important aspect of electric power markets this summer is that wholesale prices are likely 

to be quite a bit higher than last year. Forward prices from the InterContinental Exchange are 50 to 

90 % higher than last summer’s prices. They are higher almost everywhere, in both RTO and nonRTO regions. The degree of increase depends on how often natural gas is the marginal fuel being 

burned, not on whether a region is part of an RTO. Thus, the largest increases appear in the 

Northeast where gas is almost always on the margin. The lowest appear in the Midwest, where coal 

is more often on the margin. 

These prices are important, but I need to give you two cautions in using them. First, forward prices 

are not predictions of the future. They are the price that willing buyers are paying – right now – to 

willing sellers for deliveries this summer. That may or may not be where the prices end up. In any 

case, they are already affecting eventual costs – those who hedge their positions with forward 

transactions are locking in this price already as part of their summer portfolio.

Second, there is no direct relationship between wholesale and retail electric prices. The effect of 

higher wholesale prices in short-term markets on retail prices varies based on the reliance on shortterm purchases.
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Gas Prices Higher Gas Prices Higher 

in 2008 in 2008

Source: Derived from 

ICE and NYMEX data

Why are forward electric prices so high for this summer? 

Let’s look at natural gas prices first. The slide shows that the American natural gas price has been rising 

rapidly since the start of the year. Forward prices are also higher for the rest of the year, even though 

American gas production is rising. Why? 

First, last winter was a roughly normal winter, but that was considerably cooler than the two previous 

winters. So natural gas storage levels are lower going into this summer. Market participants need to buy 

more gas through the summer to make up the difference.

Second, demand is rising, especially for electric power. Given today’s generation fleet, natural gas will fuel 

most of the increase in electric power demand around the country. Last year, generators burned about 10 % 

more gas than in 2006. So far this year, it is up again – 11 % compared to last year.

Third, imports will probably fall. Canadian imports are down a little so far this year. LNG imports are likely 

to be down as well. In the first four months of the year, they were down by 62 %. In the spring and summer 

of last year, British gas prices were $3 to $4 per MMBtu. We imported record volumes with an American 

price in the $6 to $8 range. This year, the British price is above $11, about at parity with the Henry Hub 

price. So we will probably import more than the first four months would suggest, but still less than last year –

especially to Gulf Coast ports. 

Finally, there appears to be global commodities boom in most raw materials.

All these factors tend to increase gas price for the summer. The increase in domestic production is 

substantial and works the other way. Overall, gas prices are rising – but for the same heat content, they 

remain at only about half of current oil prices.

Continued on next page
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Continued from previous page

Natural gas is the most influential factor affecting electric power prices, because in the summer 

natural gas is on the margin more often and in more places than any other fuel. But other factors also 

matter. For example, last summer wholesale electric prices went up faster than fuel prices, 

especially natural gas. That could happen again. The United States has added little baseload

capacity over the last few years. As a result, if loads continue to rise, the electric system must use 

generators that cost progressively more to run. The market clearing price should normally rise 

enough to make it worthwhile to run those generators. The shift of what is on the margin can be from 

coal-fired units to gas-fired ones, or from combined cycle units to combustion turbines. Either way, 

the result is normally higher prices, even if fuel prices stayed the same.
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Regional Reliability Regional Reliability 

Highlights Highlights

 West – Southern California Concerns Southern California Concerns

 ERCOT – Wind Operational Wind Operational 

Challenges Challenges

 Southeast Southeast – Drought and Demand Drought and Demand 

Forecast Forecast

West

While the reserve margins in WECC look sufficient, transmission limitations continue to constrain the 

ability to deliver these reserves from northern to southern California. Under normal conditions, it is 

expected that demand response, voluntary conservation and use of interruptible loads may be required 

this summer in southern California. The risk assessed by CAISO for a Stage 3 Emergency this year is 

greater than last year. 

Hotter than forecasted temperatures, as has occurred the previous two years, coupled with major 

generation and or transmission outages in southern California, could result in rolling blackouts due to 

shrinking operating reserves. This remains a concern, despite the implementation of demand 

response of more than 1400 MW.[1]

ERCOT 

Wind generation in Texas is expected to increase by over 3,700 MW this summer compared to last 

summer. This increase in variable generation will present additional operational challenges and may 

result in congestion, limiting the available wind output and requiring more frequent reliance on demand 

response.

Southeast

At the present time, the drought conditions in the southeast are improving in many areas. All subregions performed studies and identified no significant reliability issues for this summer based on 

continued spring rains. 

The Regional demand for SERC was under forecasted in each of the prior two consecutive summers 

close to 10,000 MW. For 2008 the demand is again projected to decrease, in this case, by 2.8% from 

the actual demand of summer 2007.

The low demand forecast, coupled with the drought conditions, require close monitoring of reliability 

risks and mitigation plans this summer. 

[1] CAISO 2008 Summer Loads and Resources, April 28, 2008, Table 16, Page 24.
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Major West to East Major West to East 

Congestion in PJM Congestion in PJM

5004/5005 Interface

17% 17% 6%

AP South AP South 

8% 

6%

Bedington-Black Oak Black Oak 

63% 63% 39%

Cloverdale-Lexington

42% 42% 12%

of Hours of Hours 

Congested

of Total PJM of Total PJM 

Congestion Congestion 

Costs

%

%

Source: Derived from PJM Market Monitoring 

Unit’s “2007 State of the Market Report, 

Volume 2: Detailed Analysis”

I’ll start in the Northeast. 

In 2007, New York and New England alleviated the most acute sources of congestion on the East 

Coast. The Neptune line greatly reduced congestion into Long Island. Transmission upgrades in 

Connecticut and Boston reduced congestion in New England. However larger, though less acute, 

issues remain.

For example, in PJM, West to East congestion is increasing. In 2007, the overall incidence of 

congestion in the day-ahead market increased by about 11 %, and it’s up again this year so far. The 

congestion is increasingly concentrated in four major bottlenecks - shown on the slide - that limit 

flows from West to East. As you can see from the peach colored numbers on the slide, BedingtonBlack Oak was congested 63 % of the time in 2007. Together, these four constraints accounted for 

over 60 % of all congestion in PJM in 2007 – the blue numbers on the slide.

West to East congestion affects prices. In 2007, wholesale power prices averaged $66/MWh for 

PEPCo in the mid-Atlantic, and only $46 for AEP in Ohio. 

PJM has been working hard to alleviate the congestion. For example, PJM estimates that the TrAIL

project would add about 5,300 MW of West to East transfer capability. The line could be in service 

as soon as the summer of 2011, if it receives needed permits later this year. But until upgrades 

come on line, increasing loads are likely to increase both the incidence and cost of congestion.
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Gas Supports Growing Gas Supports Growing 

Markets: Florida Markets: Florida

Source: Derived from 

Bentek Energy, EIA

Gas Fired 

Generation

Cypress

Gulfstream

Florida Gas

Turning to the Southeast, Florida is the fastest-growing energy market in the region. Electrically, 

Florida has relatively sparse connections with the rest of the Southeast. The state depends heavily 

on natural gas for both existing and new power generation. The yellow bars on the slide show that 

Florida’s gas-fired generation has increased by 19 % between 2005 and 2007. So far in 2008, it’s up 

again, 11 % higher than the same period last year. The smaller bars show how throughput has 

increased to meet demand on the three major gas pipelines serving Florida.

Reporting of market prices for gas is sporadic for peninsular Florida; power prices are even less 

transparent. The indications we can see suggest that in the summer, Florida often places a higher 

value on natural gas than any other part of the country, including New York and New England. This 

is symptomatic, in part, of being at the end of the pipelines.

Fortunately, Florida has been able to add new gas pipeline capacity. Last year, the Cypress Pipeline 

added 265MMcf per day of capacity. This year that has expanded by a further 116 MMcf per day. 

Later this year Gulfstream is scheduled to increase capacity by 500 MMcf per day. 
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Source: Bentek Energy

El Paso North Leg

Transwestern

El Paso South Leg

Phoenix 

Lateral

Gas Supports Growing Gas Supports Growing 

Markets: Arizona Markets: Arizona

Gas Fired Gas Fired 

Generation

In the West, Arizona is a rapidly growing market - Phoenix is now larger the Philadelphia, and 

Maricopa County, outside Phoenix, is the fastest growing county in the country. Electric power 

demand is rising quickly – and that means rapidly increasing use of natural gas.

In 2007, Arizona consumed 113 TWh, an increase of 11 % over 2005. Almost all of that increase 

came from greater use of natural gas. Natural gas used for electric power was up by 32 %. You can 

see on the slide how gas usage in generators grew in the state, and how utilization rose for pipelines 

entering the state. Indeed, this April, for the first time, all three of the major pipelines entering the 

state operated at 95 % of capacity.

Unlike Florida, Arizona is not at the end of the line for natural gas. As a result, there are many ways 

to meet increasing Arizona demands, not just the option of increasing mainline capacity from points 

further East. For example, when more Rockies gas reaches Southern California through El Paso’s 

1903 line, that frees up pipeline capacity to add service to Arizona. For example, Transwestern

Pipeline is adding the Phoenix lateral you can see on the slide to take gas that would have gone to 

California to the Phoenix area instead. 

The American pipeline industry has proven adept at adding this sort of flexibility over the years. As 

things stand now, Arizona has met and is meeting its growing needs without seeing its natural gas 

prices rise any faster than in other parts of the country.
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Summer Weather Summer Weather 

Forecast Forecast

Source: MDA EarthSat Weather

What are the biggest unknowns in looking at the summer? The biggest variable is the weather. A 

cool summer could keep electric prices far below the levels that many people expect, as they did last 

year in Texas. Conversely, a hot summer could raise prices and reliability concerns even more.

The slide shows the current forecasts for the summer.

The other major weather factor is hurricanes. So far, forecasters say that we can expect a more 

active year than normal. They are guessing that we will see about 15 named storms, 8 of which will 

become hurricanes. They say there is a 69 % chance that a major storm will make landfall in the 

Untied States. We saw in 2005 what badly placed hurricanes could do to energy prices. Indeed, one 

of the forces that may be keeping gas prices relatively high is the fear of hurricanes.
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2008 

Summer Market and Summer Market and 

Reliability Assessment Reliability Assessment

Item No.: A-3

May 15, 2008 May 15, 2008

Thank you very much. We welcome your questions.