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Natural Gas and Electricity Costs and

Impacts on Industry

DOE/NETL-2008/1320

White Paper on Expected Near-Term

Cost Increases

April 28, 2008



Disclaimer

This report was prepared as an account of work sponsored by an agency of the United StatesGovernment. Neither the United States Government nor any agency thereof, nor any of theiremployees, makes any warranty, express or implied, or assumes any legal liability orresponsibility for the accuracy, completeness, or usefulness of any information, apparatus,product, or process disclosed, or represents that its use would not infringe privately ownedrights. Reference therein to any specific commercial product, process, or service by trade name,trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement,recommendation, or favoring by the United States Government or any agency thereof. The

views and opinions of authors expressed therein do not necessarily state or reflect those of theUnited States Government or any agency thereof.



Natural Gas and Electricity Costs and Impacts on Industry

DOE/NETL-2008/1320

A White Paper on Expected Near-Term Cost Increases

April 28, 2008

NETL Contact:

Peter C. BalashOffice of Systems, Analyses, and Planning

National Energy Technology Laboratory

www.netl.doe.gov



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Table of Contents

Summary…………………………………………………………………………. 1Background………………………………………………………………………. 1

Forecast Electricity Growth……………………………………………………… 3Opposition to New Coal Plants and Natural Gas Prospects……………………... 4Effect of Possible Climate Legislation…………………………………………... 9Conclusion……………………………………………………………………….. 11

List of Figures

Figure 1: Total Natural Gas Supply to U S. ……………………………………… 1Figure 2: Real Natural Gas Prices vs. Gas Power Capacity Additions…………… 2Figure 3: Change in KWH, 2006 v 1999, by State………………………………… 3

Figure 4: Total Electricity Generation Growth Rates……………………………… 4Figure 5: Can Natural Gas Supply Support a “Dash for Gas?”……………………. 5Figure 6: Theoretical Coal Displacement by Gas………………………………….. 6Figure 7: 2006/7 Average and Peak Monthly Generation, Gas Combined Cycle…. 7Figure 8: Expected Reserve Margins by Region, 2016……………………………. 8Figure 9: Incremental Natural Gas Demand

with Higher Growth, No New Coal, and Climate Legislation………….. 9Figure 10: Effect of $30/t CO2 tax and $14/mmBtu Natural Gas on

Current Average Generating Costs, by Region…………………………. 10



Prepared by:

Peter C. Balash

NETL/OSAP

Kenneth C. Kern

NETL/OSAP



Acknowledgements

We would like to thank Erik Shuster and Christopher Nichols of NETL’s Office of Systems,

Analyses, and Planning (OSAP) for supporting work. All opinions and conclusions, however,are solely those of the authors.



1

Natural Gas and Electricity Costs and Impacts on Industry

Summary: Natural gas prices continue their recent upward trend. High natural gas prices hurtall natural gas consumers, especially households and natural gas-intensive industry, with recentprices three to four times higher than a decade ago. Trade-exposed industry has been hurt the

most. Regions of the country dependent on natural gas fired generation have experienced largeincreases in the cost of power. Coal-fired generation has restrained the price of electricity andhas constrained the price of natural gas from matching the rise in the price of oil. Currently,opposition to coal plants and uncertainty over nuclear power has stymied the construction of newbaseload generation. This threatens a capacity shortage in many areas of the country, in the nearterm. Additionally, should climate change legislation pass, the “dash to gas” will beexacerbated, doubling natural gas consumption for power generation, increasing dependence onforeign energy sources, and sending natural gas and power prices skyward across the country.

Background

In the early part of this decade, natural gas optimism was high. EIA reflected industry consensuswith projections of over 29 trillion cubic feet (Tcf) by 2010 and nearly 35 Tcf by 2020. Theprojections were based on the extrapolation of high growth rates of natural gas use in powergeneration, underpinned by assumptions of continued growth in domestic U.S. natural gasproduction and available Canadian imports.

’’0606

Total Natural Gas Supply to U.S.(Including LNG)

T c f / Y e a r

T c f / Y e a r

’’0101

’’0202

’’0303

’’0404

’’0505

’’0707

’’0808

Annual Energy Outlook 2001, 2002, 2003, 2004, 2005, 2006, 2007 and 2008 March revision reference cases

’’0808no LNGno LNG

Gradual Decline to < 20 Tcf without LNGGradual Decline to < 20 Tcf without LNG

Increased Use of Natural Gas in Electricity Will Require LNG; N. American Natural Gas Supply for U.S. Trending Down

Figure 1

The decline in the FY08 forecast from the FY01 forecast for year 2020 alone, excludingLNG, is roughly 13Tcf, or nearly equivalent to the expected annual supply from ten Alaskan



2

pipelines. The main driver has been the increase in natural gas price and the availability of substitutes, especially coal, embedded in the model. For U.S. natural gas supply to remainflat, growth in LNG supply is required. Domestic production is projected to decline steadily,falling below 20 Tcf by 2030 (Figure 1). This implies that significant energy security issueswill arise for the supply of natural gas, in addition to long-standing issues for secure

petroleum supply.

Installation of a large amount of natural gas-fired capacity – combined cycle units andcombustion turbines - drove natural gas demand much higher. However, disappointing U.S.production, declining Canadian imports, minimal LNG imports to date, and the continuedrise in the price of oil have caused natural gas prices to more than triple between 2002 andtoday (Figure 2).

Real Natural Gas Prices v. Gas Power CapacityAdditions

0

50

100

150

200

250

1 9 8 9

1 9 9 0

1 9 9 1

1 9 9 2

1 9 9 3

1 9 9 4

1 9 9 5

1 9 9 6

1 9 9 7

1 9 9 8

1 9 9 9

2 0 0 0

2 0 0 1

2 0 0 2

2 0 0 3

2 0 0 4

2 0 0 5

2 0 0 6

2 0 0 7

2 0 0 8

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

$10.00

cumulative adds Avg HH Pr ice

Source: EIA Natural gas Navigator, Annual Energy Review 2006,Annual Energy Outlook 2008; BEA: GDP deflator; NETL calculations

$/mmBtuCumulativegas capacityadditions(GW)

Real gas prices have increased by a factor of 4,

spurred in part by massive gas capacity increases

Figure 2

Natural gas has not matched price the percentage increase in the price of oil because of competition offered by coal, and favorable weather in two of the past three winters. That is, inprevious projections natural gas was assumed to take market share away from coal due tocompetitive electricity costs. However, high natural gas prices caused the cost of electricity fromnatural gas to be higher than that from coal. Because of this, and because in many regions therewas surplus electricity capacity, electricity prices were not high enough to make natural gasgeneration economic. As a result, natural gas combined cycle (NGCC) units averaged about 40%capacity factors in 2007 compared to well over 70% in 2002. The warm winters of 2005-2006and 2006-2007 meant that residential space heating consumption was much lower than normal,preventing the natural gas price from rising along with oil, but not enough for the price tosignificantly displace coal. As of mid-April 2008, the price of oil is $115/barrel while the priceof natural gas is $10.30/mmBtu. An historic 8:1 oil/natural gas price ratio implies a natural gasprice of $14/mmBtu; strict energy equivalence implies a natural gas price of $19/mmBtu.



3

In trade-exposed sectors of industry, especially aluminum, fertilizer, and chemicals, the rise innatural gas prices, which in the first part of the decade was U.S.-centric, caused production to beshut in or moved offshore.

1Middle East production of chemicals, especially, threatens the

competitive position of U.S. industry because of cheap natural gas reserves in the Persian Gulf area. In addition, natural gas-centered production in the U.S. is also disadvantaged relative to

coal-based industry in China.

Change in KWH, 2006 v 1999, by State

CA

DE ID

DC RI HI KSWV

MN

TX

KY

CO

IL

NV

TN

IN

MO

NE

PA

IA

AL

OK

AR

WYFL

NMAK

UTNDVTSDMS

AZMA

WI

NH

GA

SC

MEOR

CT

MT

VA

MILA

NJMDNC

NY

WA

OH

-30000

-20000

-10000

0

10000

20000

30000

40000

50000

60000

R+C change ind change

90% of industrial load loss in 10 states70% in 5 states

G i g a

W a t t H o u r s

Source: Derived from EIA: State Historical Tables

Residential and Commercial use grows in all states; Industrial use varies

Figure 3

Forecast Electricity Growth

Current projections of electricity generation growth, and in particular sales to industry, are only1.1% and 0.1% per year, respectively, according to EIA Annual Energy Outlook 2008

2. In fact,industrial sales growth is deemed to turn negative after 2017. This appears to be an extrapolationof the most recent period, encompassing the blows to industry caused by the fuel price run-up, amanufacturing recession centered in Ohio, and industrial retrenchment in California and NewYork (see Figure 3).

1 See, for instance, American Chemistry Council, “Impact of High Energy Costs on Consumers and Public,”testimony before the U.S. House of Representatives, Energy and Mineral Resources Subcommittee, May 19, 2005.Available at http://www.americanchemistry.com/s_acc/sec_policyissues.asp?CID=311&DID=1137 2 EIA, Annual Energy Review 2008, annual tables, Table 8.



4

-3%

-2%

-1%

0%

1%

2%

3%

4%

5%

6%

7%8%

9%

10%

1980 1990 2000 2010 2020 2030

P e r c e n t c h a n g e f r o m p

r e v i o u s y

e a r

1.5%/yr NERC

Total Electricity Generation Growth Rates

AEO AEO ’ ’ 08 08

1.7%/yr 6 yr

1.1%/yr EIA

Electricity generation: EIA,1949− 1994: Annual Energy Review 2006; 1995− 2006: Electric Power Annual 2006; 2007 − 2030: Annual Energy Outlook 2008 revision; NERC 2007 Long-Term Reliability Assessment

2.4%/yr 20 yr

Forecast for Electricity Generation Growth Well Below Recent Averages

Figure 4

Even then the growth rate used for the projection (1.1%) does not reflect recent averages(1.7% - Figure 4). Extrapolating based on a time period with these embedded events willlikely underestimate electricity consumption over the next few years, once the currenteconomic slowdown is resolved. Worse, underestimation of industrial growth over thelonger term risks becoming a self-fulfilling prophecy, as demand uncertainty may lead tofailure to install enough electricity generation capacity, causing the price of electricity to rise

needlessly and further weakening U.S. industry.

Opposition to New Coal Plants and Natural Gas Prospects

The current push by certain interest groups to forestall the construction of coal fired powerplants, reminiscent of opposition to nuclear power, threatens to:

a. reduce already precarious reserve margins, raising the risk of blackout, andb. increase the demand for natural gas in the short to medium term.

Expecting natural gas generation to displace coal-fired generation is, at best, problematic. By2016, in the absence of 18 GW of currently forecast new coal-fired plants, the addition of

natural gas plants to supplant these kWh would demand 1.4 Tcf/year, or almost all of thepresently forecasted LNG growth. If electricity growth is higher, in line with AEO’05estimates, due to better macroeconomic performance, an additional 2.3 Tcf of natural gas forgas-fired generation would be needed.



5

Can Natural Gas Supply Support a “Dash to Gas?”

2.3 Tcf

1.4 Tcf

Data source: Energy Information Administration’s Annual Energy Outlook 2008 (revision) and AEO2005. Assumes that NG-firedcombined cycle plants operating at 50% efficiency to fill generation gaps

Coal AEO’08

Nuclear AEO’08

Total generation AEO’05

Oil and Natural Gas AEO’08

Renewable AEO’08

Generation from coal if no new plants are built

Total generation AEO’08

3.7 TCF of Potential Natural Demand Growth with Declining N. American Supply

Figure 5

Although LNG regasification capacity could grow by as much as 15 bcf/d, only 5 bcf/d iscertain to appear. Currently LNG capacity is 5 bcf/d, and EIA only expects 3.2 bcf/ of LNGimports by 2010, implying significantly underutilized regas capacity. Industry’s perceptionof likely prices for LNG has also changed. In 2003, Deutsche Bank as well as other energyanalyst groups expected LNG to cause world prices of natural gas to clear at $3.50/mmBtu.In 2008, the bank notes the success of the United Kingdom in bidding away surplus LNGcargoes, even though U.S. prices are above $10/mmBtu.3 At the same time, U.S. domestic

production is not expected to grow, and Canadian imports are expected to decline.

3 Deutsche Bank AG, Natural Gas Outlook 13 June 2003, p. 2; Commodities Weekly 18 April 2008.



6

Wall Street Journal , April 18, 2008

Thus, the likely way for LNG to increase natural gas supply to the US is for price to risesubstantially. This increase could happen, thanks to the confluence of the pressure on coalutilization and the related possibility of climate change bills.

Theoretical Coal Displacement by Gas

0%

20 %

40 %

60 %

80 %

100%

120%

140%

160%

W E CC ERCO T FRCC M RO SP P SE RC RFC NP CC L-48

gas @ 0.65

gas @ 0.85

Nationally, 20-35% of coalkilowatt-hours can be displaced

by operating existing NGCC unitsat higher capacity factors*Percentage of

displacedcoal generation

*Note: abstracting from constraints Source: Energy Velocity database; NETL calculations

Most coal-dependent regions have limited ability to displace coal with gas to displace emissions

Figure 6

Nationally, up to a third of coal kilowatt-hours could be displaced by higher utilization of natural gas combined cycle units (NGCC), as shown in Figure 6. Coal-dependent regions



7

such as SERC and RFC drive this result, with limited available NGCC capacity. While itmay appear NPCC has enough combined cycle capacity to replace its modest coal use, thatsurplus does not exist during peak months.

2006/7 Average and Peak Monthly Generation,Gas Combined Cycle

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

RFC MRO SERC SPP WECC NPCC ERCOT FRCC

0%

10%

20%

30%

40%

50%

60%

70%

80%

avg CC mwh peak CC mwh 2006 CC avg cf 2007 CC peak cf

Capacity factors

Monthly TWh,averageand peak

In the West, Northeast, Texas and Florida, gas CC units operating over 65% cf at peak month in 2007

Existing NGCC can not meet peak load growth

Source: Ventyx Energy Velocity database

Figure 7

Other, more natural gas-centric regions such as NPCC have limited ability to displace coalwith existing natural gas plants because these plants already operate at high capacity factors

during peak months (Figure 7). More capacity is clearly needed.



8

Expected Reserve Margins by Region, 2016

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

RFC NPCC SERC SPP MRO FRCC EAST* ERCOT WECC

2016 2016, no new coal 2016, no new coal or nuclear

*East = combination of RFC, NPCC, SERC, SPP, MRO, and FRCC

Most of the country will be in precarious situation in 2016 w/o new baseload; the East will be vulnerable even with expected plants

“comfort” reserve margin level

Source: Ventyx Energy Velocity database, 4/15/2008

Reserve margin

Figure 8

The Eastern Interconnect (all regions excluding ERCOT and WECC) is in dire need of newcapacity to ensure safe reserve margins by 2016 (Figure 8). The loss of new coal plants willreduce reserve margins well below these levels for most of the country, other than ERCOT(Texas) and SPP. However, since SPP is in the “East” its surplus will be drawn off by thegrid. Should nuclear power also not be available before 2016, the entire Lower-48, saveERCOT, will be at high risk of power shortages, a present-day South African-like, electricitysupply situation.

The compound influence of these factors could more than double current U.S. powergeneration consumption of natural gas, just from running existing combined cycle units athigher rates, and with incremental new gas-fired additions.



9

Incremental Natural Gas Demand w/ HigherGrowth, No New Coal, and Climate Legislation

5.77

8.77

14.35

*existing gas CC plants at 65% capacity factor** existing CC at 85% cf.

Figure 9

In Figure 9, consumption in 2008 of natural gas by combined cycle units will be about 5.1Tcf. From Figure 5, an additional 3.7 Tcf of natural gas would be needed to replace expectedcoal plants and accommodate higher growth. In the event of climate change legislation,running existing natural gas combined cycle units at higher capacity factors can displace 20-35% of current coal kilowatt-hours (Figure 6). Such substitution requires another 5.4 Tcf peryear. Clearly, the existing natural gas fleet cannot meet the growth in peak demand expectedbefore 2016 and also substitute for coal to meet carbon caps. More plants would be needed,

resulting in the incremental natural gas requirements of Figure 9.

Since the approximate 9 Tcf increase in natural gas consumption would be occurring at highprices, the impact on the economy would be severe. Since both power and heating priceswould escalate, no sector would be exempt, but energy-intensive industry and residentialsectors would certainly bear the heaviest burden.

Effect of Possible Climate Legislation

There is however, one scenario, becoming increasingly likely, that could bring to pass highnatural gas plant utilization, low to dangerous reserve margins, and the collapse of U.S. industrialcompetitiveness. A climate change bill with relatively strict cap and trade provisions, such as

S.2191, combined with the attempted moratorium on coal and likely delay of nuclear wouldseverely impact the U.S. economy as it attempts to adjust.



10

Figure 10

Electricity and natural gas-intensive industry will be targeted. These effects have beenminimized by most analyses because they neglect the vicious cycle between the prices of natural

gas and of carbon dioxide; in the short term, under a cap and trade, the price of carbon must behigh enough to displace coal kilowatt-hours. Only natural gas generation can do this at sufficientscale. Most analyses assume cheap and plentiful natural gas, early nuclear, or unlimitedbiomass, each a problematic assumption. While states with high rates of coal use will be mostimmediately affected, the knock-on natural gas demand effects will be widespread. Due to theincrease in natural gas demand as coal power is backed down, the price of natural gas will risedramatically across the country, not only in coal-using regions. As the natural gas price rises,

coal plants regain competitiveness, necessitating a further rise in the carbon dioxide allowance

price, in order to meet the cap. A price of $14/mmBtu, usually seen only in peak days in theNortheast, could be come commonplace. (This price equates to a price of oil of $84/barrel at a6:1 energy equivalence ratio and $112/b at a more normal 8:1 ratio). The combined effect of

high fossil fuel prices and a carbon dioxide allowance price of $30/ton would drive the averageMWh cost to well over $110/MWh in natural gas-heavy regions (Figure 10). In fact, in Figure10, the absolute cost increase of electricity is 31% higher in natural gas-intensive regions than incoal-intensive ones. On top of the already precarious reliability situation, shortages of natural gasand power may occur before relief arrives with advanced, but expensive, power generationtechnologies.



11

Conclusion

Since 2001, perceptions of natural gas supply and consumption have been successively ratcheteddown, without any assurance the decline has halted. Nonetheless, recognition of the extremelydifficult natural gas supply situation facing the United States has not been fully appreciated inrecent energy and climate change analyses. Policies that encourage the use of natural gas to

substitute for coal in power generation could very well lead to spectacular price increases forhouseholds and industry. As prices are pushed higher the need for more LNG will create closerlinks to the world oil price, setting the stage for the marginal price of U.S. electricity to be set bythe whims of foreign oil/LNG suppliers, for the first time in U.S. history. This blind eye towardsU.S. energy security extends to the inability to recognize that the nation's coal supply could helpthe U.S. forestall this situation. The current opposition to baseload power, and in particularcoal-fired plants, in anticipation of climate change legislation, will have serious and damagingimplications for the reliability of electricity supply and the viability of the U.S. economy in theinitial, costly period of adjustment to a carbon control paradigm.

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