1

Increasing Costs Increasing Costs 

in Electric Markets in Electric Markets

 Item No.: A Item No.: A-3

 June 19, 2008 June 19, 2008 

Mr. Chairman and Commissioners, good morning. I am here to present the Office of 

Enforcement’s assessment of likely electricity costs in coming years. This presentation will 

be posted on the Commission’s Web site today.
2

Forward Market Prices Forward Market Prices 

Continue to Climb Continue to Climb

Sources: Summer electric forwards data is July-August 2008 data from ICE as of 6/16/08. Actual on-peak data for 

2007 are from Platts Megawatt Daily. The Henry Hub data is July-August Clearport data from Bloomberg as of 6/16/08.

Southern California Southern California 

(SP-15)

$ 139.41/MWh +88 %

Northwest (Mid C)

$ 105.66/MWh +70 %

PJM Western Hub

$ 144.38/MWh +79 %

New York City

$ 208.51/MWh +123 %

Massachusetts Hub

$ 141.25/MWh +94 %

Midwest ISO (Cinergy)

$112.12/MWh +62%

Palo Verde

$ 132.95/MWh +76 %

Henry Hub (Gas) Henry Hub (Gas)

$ 12.99/MMBtu +108 %

At last month’s meeting, we reported that forward market prices for electric power are much 

higher than the prices we actually experienced last year. This trend is universal around the 

country. The slide shows the increases in forward prices for July and August as of this 

week. They have risen further during the last month as natural gas prices have continued to 

rise. 

There is little reason to believe that this summer is unusual. Rather, it may be the beginning 

of significantly higher power prices that will last for years. The purpose of this presentation 

is to explain why that is so. The two major factors pushing the costs of electric generation 

higher are increased fuel costs and increased cost for new construction. These factors affect 

all parts of the country. That is, higher future prices are likely to affect all regions. 
3

Forward Gas Prices Forward Gas Prices 

Remain Strong Remain Strong

Source: Forward gas 

prices are Nymex. 

Annual average spot 

gas prices are Platts. 

The primary reason for the electric power price increases this year is high fuel prices. All 

current market indications suggest that they will remain high. Let’s look at natural gas, 

which often determines prices because it is so frequently on the margin. The slide shows 

futures prices for the next few years. The futures prices are somewhat lower for 2009 than 

for 2008. Even so, they are a good deal higher for all years than the prices people actually 

paid last year, and they are much higher than the prices many of us remember from earlier 

in the decade. The implication is that markets anticipate continuing high prices, even 

though they know that the United States has seen a significant increase in domestic natural 

gas production over the last year and a half. The anticipation of further high prices makes 

more sense when one considers the likely increase in gas demand for generation and the 

global nature of competition for LNG.
4

Coal Prices Increasing Coal Prices Increasing 

and Strong and Strong

Source: Forward coal 

prices are Nymex. 

Coal Spot Prices are 

Bloomberg.

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

$110

$120

2007 2008 2009 2010 2011

Prices ($/ton)

C entral Appalachia

C oal Futures

C entral A ppalachia

Spot C oal P rices

P owder River Basin

C oal Futures

P owder River Basin

Spot C oal P rices

Natural gas is not the only important fuel in setting electric power prices. Coal still powers 

half of all power produced in the U.S. In some markets – the Midwest and the Southeast, 

for example – coal is often on the margin and plays a major role in setting average prices 

over time. The slide shows that the price of one key form of coal – Central Appalachian 

coal - has risen rapidly over the last year. Forward markets show continuing high prices for 

Central Appalachian coal for the next three years. This reflects, in part, the growing global 

market for coal and the relatively weak US dollar. Coal imports are becoming more costly 

and coal exports more profitable, both of which contribute to higher prices in the United 

States. 

I should mention that other coal prices behave somewhat differently from Central 

Appalachian coal. For example, a majority of the overall cost for Powder River Basin coal 

comes from transportation rates and can be more difficult to see. Nonetheless, the 

implication of the prices we can see is that electric power prices are likely to increase even 

where coal is on the margin. This may take place somewhat differently from the way 

natural gas price increases flow through into power prices. Generally, companies buy coal 

under fairly long term contracts, so there may be a lag before the higher prices show their 

full effects. But the effects are coming.
5

Net Natural Gas Net Natural Gas 

Generation by Region Generation by Region

(TWh)

Source: Derived from Energy Velocity (differences due to rounding).

Northeast Northeast 66.3 103.9 37.6

RFC 41.0 64.5 23.5

SERC 86.9 150.5 63.6

FRCC 42.0 96.7 54.7

ERCOT 155.9 163.3 7.4

Midwest Midwest 44.2 62.8 18.5

WECC-Rockies and SW 28.1 77.6 49.5

WECC-CA and NW 115.4 129.7 14.4

Region 2000 2007 Difference

While both natural gas and coal prices have increased rapidly, natural gas is increasingly 

important in every region of the country. The slide shows that even in regions where coal 

has historically dominated – most noticeably in SERC– natural gas usage has grown 

substantially since 2000, up 63.6 TWh in 2007, more than in any other region. Noticeable 

increases also occurred in FRCC, which has flexibility to burn either gas or oil at many 

facilities, and also in the Rockies and Southwest where demand continues to grow 

considerably.
6

NERC Net Load NERC Net Load 

Projections through 2016 Projections through 2016

Source: Derived from NERC 

2007 Long Term Reliability 

Assessment, Oct. 2007 and 

NERC data request, June 

2008.

Northeast Northeast 9.7 17

RFC 23.2 13

SERC 28.2 14

FRCC 7.1 15

ERCOT 14.7 24

Midwest Midwest 17.2 21

WECC-Rockies and SW Rockies and SW 7.6 25

WECC-CA and NW 10.9 10

Total 108.8 14

Region Total Percent Percent 

Difference Difference Change

(GW)

The second major factor that will put upward pressure on electric power prices is the 

increasing cost of new construction. This effect is particularly important because the 

country is entering a period when we will need to make substantial new investments, 

especially in generation.

Natural gas fueled most of the last great wave of generation investment, which occurred 

between 1995 and 2004. In recent years, demand in most regions has gradually caught up 

with the capacity built around 2000. Looking forward, demand will continue to grow, and 

the need for new capacity will become ever more acute and ever more widespread. The 

slide shows NERC’s expectation of peak net load growth in different regions for the next 10 

years. We at the Commission are not in the business of forecasting, so I would just say this: 

There are legitimate reasons to be unsure about exactly how much new generation the 

country will need in the coming years. For one thing, higher prices will themselves 

discourage some power demand. Nonetheless, a significant level of demand increase seems 

virtually inevitable. So will be the need to build more capacity. 
7

Capital Costs Capital Costs 

Increasing Increasing

Source: Cambridge 

Energy Research 

Associates. 71023-12 

Cost Index (2000 = 100)

Without Nuclear

With Nuclear

Power Capital Costs Index (PCCI)

The need for new generation is important because new construction is becoming more 

expensive – quite aside from fuel price increases. Cambridge Energy Research Associates –

CERA – produces an index of costs for the main inputs that go into building new generating 

plants. The slide shows how that index has almost doubled since 2003. The increase in 

nuclear plant inputs has risen even faster. Much of this cost increase results from rising 

global demand for basic materials. Part of it also comes from shortages of people to do key 

engineering and construction jobs. In any case, the implication is that, we will pay more, 

not less, for the next round of construction. 
8

Primary Construction Primary Construction 

Costs Increasing Costs Increasing

Source: Derived from 

Bureau of Labor 

Statistics Data and 

Bureau of Economic 

Analysis data. 

Cost Index (2000 = 100)

Iron & Steel

Cement

GDP Deflator

Let’s look at some of the reasons that CERA’s index is rising so rapidly. The slide shows 

two of the primary construction materials for electric generating plants – concrete is on the 

blue line and iron and steel on the red line. As you can see, the prices of both have been 

rising recently – especially steel, which is now more than twice as expensive as it was four 

years ago. Rising costs for iron and steel will also affect fuel prices for the power industry. 

For example, natural gas wells and pipelines both use substantial amounts of steel, so 

natural gas costs will also reflect rising iron and steel prices. 
9

Secondary Construction Secondary Construction

Costs Increasing Costs Increasing

Source: Derived from 

Bureau of Labor 

Statistics Data and 

Bureau of Economic 

Analysis data.

Cost Index (2000 = 100)

Copper

Nickel

Zinc

Aluminum

GDP Deflator

Of course, new generating plants require many other basic commodities. The slide shows 

the pricing for four key metals that go into generators. As you can see, all of these metals 

are increasing in price. The one that stands out is copper, up more than five times over the 

past four years. Indeed, copper is now so valuable there are reports of copper thieves 

cutting live cables to steal the metal.
10

Labor Costs Labor Costs 

Increasing Increasing

Cost Index (2000 = 100)

Utility Labor

Construction Labor

GDP Deflator

Source: Derived from 

Bureau of Labor 

Statistics Data and 

Bureau of Economic 

Analysis data.

Labor costs are also increasing. Perhaps the most frequently cited labor shortage is that for 

nuclear engineers. It has been a full generation since the nation built its last nuclear plant. 

Most of the engineers who worked on those plants are near retirement – and many have 

moved on to other occupations. In fact, the labor shortages are more widespread than just 

nuclear engineers. The slide shows that there has been about a 27% nominal change in 

average hourly earnings for both construction labor generally and for non-construction 

utility labor since 2000, outpacing inflation by over 4% for the same period.

In practice, the American labor market is quite responsive to market forces, so short-term 

labor shortages tend to be self-correcting over the mid-term. Still, there is no quick way to 

force several years of education into six months, or decades of experience into a year or 

two. 
11

$0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000

Estimated Cost of Estimated Cost of 

New Generation New Generation

Nuclear Nuclear

Conventional Coal Conventional Coal

IGCC Coal IGCC Coal

Combined Cycle

Combustion Turbine

Wind

Geothermal Geothermal

Concentrated Solar Concentrated Solar

Source: Compiled by FERC Staff from 

various sources. Cost estimates exclude 

carbon capture and sequestration costs.

$/kW

2003-04

2008

What do all these cost increases mean for the cost of building a new generating plant? 

No one knows precisely. It’s difficult to get consistent and trustworthy numbers about plant 

costs, both because they are commercially sensitive and because the assumptions behind them 

vary greatly. The numbers reflected on the slide come from a variety of sources and include 

different assumptions about, for example, location or exactly what facilities are included in the 

estimate. To take one example: Two recent nuclear procurements in South Carolina and Georgia 

produced cost estimates of $5,100 and $6,400 per kW, respectively, for the same technology. We 

have been told that most of the difference may be due to different uses of Allowances for Funds 

Used during Construction – AFUDC.

Despite the difficulties in being precise, the slide represents a good general indication of how 

capital costs have been changing. If anything, the cost estimates may be lower than the final 

costs of projects, if input costs continue to rise.

It’s also important to remember that these cost estimates cover only capital costs. They do not 

include fuel costs, which as we’ve seen earlier will be a large factor for both natural gas and coalfired plants. To the extent that plants do not have major fuel costs - they may be more 

competitive over their life cycles than would be suggested just looking at the capital costs. That 

would affect renewables and, to a degree, nuclear plants.

Similarly, these estimates generally do not include a full accounting of major risk factors, 

especially those affecting coal and nuclear plants. Both of these technologies have long lead 

times. That increases the chance that market conditions will change before they are complete and 

adds to the financial risk of building them. Nuclear plants also have risks associated with both 

decommissioning and waste fuel disposal. And coal plants have risks associated with the future 

treatment of greenhouse gases. Of course, relatively new technologies like wind and the new 

approaches to nuclear also have some risks, simply because they do not have the same track 

record of more mature technologies.
12

Climate Change Debate Climate Change Debate 

Affects the Market Affects the Market

 Uncertainty about future carbon Uncertainty about future carbon 

regime is a key factor regime is a key factor

 Affects coal most of all Affects coal most of all

• Greater carbon emissions Greater carbon emissions

• Many plant cancellations Many plant cancellations

 At the least, coal builds will be At the least, coal builds will be 

delayed delayed

Climate change has become an increasingly urgent national issue. The debate over how to 

address carbon dioxide emissions is lively and has already affected how companies think 

about investments. Until recently, rising natural gas prices made coal plants attractive. 

However, the national uncertainty about carbon policy has made investing in coal plants 

more risky. Without carbon capture or sequestration, coal unit emit about four times as 

much carbon as natural gas combined cycle units per MWh. Since January 2007, 50 coal 

plants have been canceled or postponed. Only 26 remain under construction. 

Whatever the eventual result of the climate change debate, costs of producing power from 

both coal and natural gas are likely to increase. Moreover, as long as future climate change 

policy is unclear, market participants will have a considerable disincentive to invest in coal 

plants. Even when the issues are resolved, it remains an open question how competitive 

coal-fired generation will be, and it would take another four to eight years to build new 

coal-fired capacity.
13

Natural Gas is Critical Natural Gas is Critical 

in the Mid in the Mid-term

 Coal and Nuclear Coal and Nuclear – Long lead times Long lead times 

 Renewables Renewables – Important but do not Important but do not 

fill capacity needs (yet) fill capacity needs (yet)

 Demand Response and Energy Demand Response and Energy 

Efficiency Efficiency – Key ingredients Key ingredients

 Natural Gas Natural Gas – The necessary The necessary 

technology for the immediate future technology for the immediate future

Over the long run, the nation can meet its increasing need for generation in several ways. But 

for the next few years, the options are more limited, and natural gas will be crucial.

The lead times for both nuclear and coal units mean that they will not supply a significant 

amount of new capacity for nearly a decade. 

Most people expect renewables to supply an increasing proportion of the nation’s power. For 

the next few years, wind will almost certainly account for a large share of generation investment 

and will account for a growing share of overall generation. Wind power has no fuel costs, and 

so will generally operate when available. However, wind is a variable, weather-dependent 

resource. As a result, it will not make up as strong a share of the Nation’s capacity needs over 

the next few years. Other renewables are becoming more competitive. Geothermal power is 

already an important resource in the west, and concentrated solar is becoming economically 

attractive in desert areas like the Southwest. But these sources are likely to remain relatively 

small in the national picture over the next few years. 

Both demand response and energy efficiency will be important – I’ll talk more about them on 

the next slide – but they are unlikely to eliminate the need for new capacity.

Overall, the most likely outcome is that natural gas will continue to be the leading fuel for new 

capacity over the next half decade. For example, the consulting firm, Wood Mackenzie 

estimates that in a carbon constrained environment, gas consumption for power will increase by 

69 % by 2017. That’s in addition to the 55% increase we’ve seen since 2000. 
14

Potential Responses Potential Responses 

to High Prices to High Prices

 Economic Demand Response Economic Demand Response

 Energy Efficiency/Conservation Energy Efficiency/Conservation

 Technological Innovation Technological Innovation

Over the years, we have learned repeatedly that people respond to prices. In the case of 

electric power, this is likely to take several forms.

First, there is likely to be more demand response. In the simplest terms, high prices at peak 

will lead some customers – both businesses and others – to prefer to save their money rather 

than use power. In fact, the first round of demand response may be both the cheapest and 

fastest way to improve capacity margins on many systems. The best cost estimates for the 

first rounds of demand response suggest that it should be available for about $165/kW, far 

less than any generation side options. The results of ISO-NE’s first Forward Capacity 

Market auction last year corroborates the economic importance of demand response - 7.4 % 

of the accepted bids were for demand response. However, there are impediments that limit 

the full use of demand response. For example, most customers do not have the option to 

respond directly to real-time prices. As a result, they are unlikely to reduce peak 

consumption as much as they might prefer to if they could take advantage of the price.

Second, customers are likely to be more energy efficient. While few customers see realtime prices, most get an average price over a month. As a result, high prices give them 

considerable incentive to reduce their overall consumption of power – though no more at 

peak than at other times. That is, energy efficiency is essentially a substitute for baseload

capacity, while demand response is a substitute for peaking capacity. Energy efficiency is 

also likely to be economically important. Cost estimates show that the first round of energy 

efficiency may be available for about 3 cents/kWh. At

Continued on next page
15

Continued from previous page

current prices, supplying that same kWh from a combined cycle gas plant would cost 9 

cents just for the fuel. Adding to the likelihood of greater energy efficiency is that many 

states have adopted fairly strong energy efficiency standards.

Third, innovators see higher prices as an opportunity. By the nature of things, it’s hard to 

predict what innovations will succeed. The electric industry has a number of technologies 

that might take off – including concentrating solar power, hydrokinetic power, and vehicle 

to grid technologies. In addition, distributed generation is becoming more important, and 

may continue to do so for both cost and emissions reasons In other newly competitive 

industries, such as telecoms and natural gas, innovations have produced large changes, 

sometimes quickly. Given continuing high electric prices, the electric power industry may 

see similar results. 
16

Increasing Costs Increasing Costs 

in Electric Markets in Electric Markets

 Item No.: A Item No.: A-3

 June 19, 2008 June 19, 2008 

That concludes our presentation. We welcome comments and questions.