The Global Energy Big Picture (2007)

The Global Energy Big PictureFundamentals, Trends and Issues Shaping the Industry for 2007

Fall 2006

© Copyright 2006, Global Energy Decisions, LLC

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Global Energy Decisions

The opinions expressed in this report are based on Global Energy Decisions’ judgment and analysis of keyfactors expected to affect the outcomes of future power markets. However, the actual operation andresults of power markets may differ from those projected herein. Global Energy Decisions makes nowarranties, expressed or implied, including without limitation, any warranties of merchantability or fitness fora particular purpose, as to this report or other deliverables or associated services. Specifically, but withoutlimitation, Global Energy Decisions makes no warranty or guarantee regarding the accuracy of anyforecasts, estimates, or analyses, or that such work products will be accepted by any legal, financial, orregulatory body.

The Global Energy Big Picture

WECC Regional Outlook, Fall 2006 1

North America’s Merchant Energy Market is Back---Mostly

Regional power markets are recovering and higher fuel prices have helpedspeed that process. During the bust side of the power cycle, the industry’s liquiditygap was filled by financial players such as hedge funds, private equity investors, andinvestment banks which traded distressed project debt, created energy investment fundsto acquire distressed portfolios, and bottom-fished.

Merchant and financial players continue to enter the market with seriousprivate equity-backed capital. Players such as US Power Gen, Waypoint, andComplete Energy, LS Power1 and CPV are in a new growth pattern of actively pursuingacquisition targets and new development projects. Their actions add momentum andenthusiasm in the market.

Portfolio rationalization is in full swing. We expect to see an accelerated flipping ofassets sometimes several times as different potential owners pursue various portfolioswith different perceived value streams. This is a healthy sign that the markets are movingfrom triage to rationalizing investments for growth. Early entrants capitalized on the lowmarket sentiment in the middle of the bust cycle to capture the low hanging fruit and theinability of current asset owners to ‘hang on’ long enough for markets to recover.Examples include KKR acquisition of Texas Genco assets, Goldman Sachs taking severalNEGT assets through Cogentrix, and Mattlin Paterson’s KGen Partners acquired Duke’sSoutheast assets. Higher fuel prices speeded up market recovery in some regions and anumber of these players have been able to “cash out” early, as when Texas Genco was soldto NRG. Assets are also changing hands as some newly formed investment companiesdevelop their asset portfolios, while other players divest non-core assets and re-shapetheir holdings. Two players in particular, Mirant and Calpine, are working hard to emergefrom bankruptcy with “the right stuff.”

US energy assets are increasingly attractive to foreign investors because theU.S. is a stable, transparent and business friendly environment for foreign capital.Investors such as JPower2, Diamond Generating and Macquarie are looking forinvestment opportunities across the United States. We expect this trend to continue.

Liquidity in the Southeast region is still low and many assets are still owned bybanks or other debt holders. Here the players are “treading water” until the marketimproved trading debt for equity and cleaning up their portfolios and/or limiting riskexposure.

Market power issues are significant raising its head with Southeastern transactions,for example, when Entergy tried to acquire the Perryville plant, located within itsterritory, the deal generated controversy over Entergy’s perceived market power.

1 LS Power and Dynegy have announced their agreement on combining their portfolios.2 Source: JPower’s April 6, 2006 dated news release on Tenaska plant acquisition.

Fundamentals, Trends and Issues Shaping the Industry for 2007

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Fuel price uncertainty continues to be a major risk factor along withenvironmental and other regulatory concerns, a larger portfolio with both fuel andgeographical diversification may be the best way to obtain more extrinsic value fromgeneration assets. Today’s energy investors clearly understand the need for economies ofscale and adequate diversification of their portfolios. Good examples of this are therecently announced LS Power/Dynegy merchant generation joint venture and NRG’sacquisition of Texas Genco.

Could the WECC be headed for overbuild already? Despite the high reservemargin in WECC, recent concerns about local area resource adequacy (and reactions tothis summer’s weather-induced high peak loads) have caused several entities to add morenew supply in the next few years than planned only six months ago. Global Energy nowbelieves that 10,000 MW more new generation is highly likely to come on line in the nextfive years than forecast in the Spring 2006. This 10,000 MW of additional assumedsupply brings the total expected amount of new generation over the next five years to over20,000 MW of new supply, which continues to put downward pressure on spot marketpower prices.

Asset Values are Flat but Regional Value Movements are Building

Average North America asset value is at $725/kW.3 Compared to GlobalEnergy’s Power Generation BlueBook analysis a year ago, this figure hasbarely changed; however, we have seen significant value movements based on region,fuel, and asset types. Following are a few important findings:

Nuclear plant values have increased by almost 25 percent. Average Nuclearvalue is now around $1,730/kW. This increase is primarily driven by higher energycosts across all fossil fuels.

Average coal-fired generation values have dropped more than 10 percent.Coal plants continue to enjoy healthy spark spreads due to higher gas prices in theshort term; however, compared to our last valuation, average coal-fired generationvalues have dropped more than 10 percent. This is primarily driven by the significantamount of new coal generation activity, particularly in Midwest and eastern WECCregions. Global Energy now expects more new coal-fired generation will be built inthe long term. This suppresses the values of the existing coal plants in these regions.

Generators in load pockets such as New York and Eastern PJM are stillenjoying healthy cash flows. In New York City, a typical new gas-fired combinedcycle plant can be valued from $1,100/kW to $1,500/kW depending on the leverageof the investment.4

3 Unless otherwise noted, Power Generation BlueBook asset values have been calculatedas the net present value of the un-leveraged EBITDA-level expected stochastic merchantcash flows for 20 years, using a 15 percent real discount rate. This applies to all assets, eventhose which are insulated from merchant risk due to ownership by vertically integratedelectric utilities.4 NPV range is calculated with 10 percent and 15 percent real discount rates.


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Capacity payments are a key component of recovering asset values in theNortheast and Mid Atlantic regions. Projected revenues from capacity marketsaccount for $188/kW in eastern PJM, over $450/kW in New York City, and around$216/kW for New England markets.

Despite all the confusion in the Western market about resourceadequacy, we are projecting the WECC market getting into a largeroverbuilt status. Particularly in California, without the support of a contract with autility, the assets will have a hard time generating enough revenue from energymarkets only. Obtaining a contract with a utility is a critical risk as there will be moreresources competing for it.

The gas-fired generation values are slowly recovering in Southeastmarkets. Liquidity and transparency are still key issues in these markets andgenerally transmission access is the primary source of conflict between IPPs andutilities. Realizing the full option value of an asset in these markets is challenging.

The bottom line is that competitive wholesale power markets have clearly swung from thecorrection stage of the power business cycle to build-up. Some markets are recoveringfaster than others with new players leading the charge. Will they be smarter than those inthe previous boom stage of the industry---we’ll see.

Oil & Gas Prices Fall Back

Natural Gas Prices - Natural gas prices are forecast to remain high for the next fewyears, albeit lower in the near months. From current low levels, prices are assumed to riseby this winter, then over the 2008-2012 period prices are expected to decline, reaching anannual average low of $4.86/MMBtu in 2012 at the Henry Hub and stay within $4.86-6.13/MMBtu range up until the year 2025, and thereafter gradually rising to$6.72/MMBtu by 2030. During the period 2012 through 2030, Henry Hub pricesgradually rise on average by about 1.82 percent annually in real dollars.

The natural gas and oil price run-up since Hurricanes Katrina and Rita has subsidedsomewhat following a warmer than usual winter and record natural gas storage levels.Together, these factors and increased industrial sector demand destruction have causedgas prices to range mostly between $6-8/MMBtu during the spring and summer of 2006,very recently dropping into the $4 range.

However, new sources of supply concern—such as occurred in Europe with accusations ofgas supply withholding between former cold war adversaries—has rekindled calls forgreater diversity of supply across Europe. Developments in the Middle East—especially inIraq and Iran—and elsewhere in Africa are also uplifting world oil prices throughincreased “security” premiums being sought by producers or traders holding longcontracts.

For North American energy consumers, even such faraway events indirectly impactenergy market prices. In the current environment of razor thin excess productive capacity

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margins for both oil and gas, even the slightest market hiccup abroad causes pricevolatility. Figure ES-3 shows historical gas prices at Henry Hub.

Figure ES-3Historical Henry Hub Spot Prices

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Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06

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Energy Crisis/ Market manipulation

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Hurricane Lili

Weather EventPerception of shortsupply / CrudeSympathy

Hurricane Ivan

Hurricanes Katrina and Rita

Expectation ofa Cold Winterand ThinSupply

SOURCE: Global Energy, NGI.

Transmission Issues Plod Forward

Transmission market regulatory events are playing a big role in energy markets across thenation. CAISO MTRU recently received the FERC contingent approval to pursue its

Market Redesign and Technology Update project to operate centralized day-aheadmarkets and institute a locational marginal pricing (LMP) mechanism in itsgeographic footprint to determine congestion costs. The target for implementingMRTU is November 2007, but that date seems aggressive given changes FERC isrequiring CAISO to complete prior to implementing MRTU.

Energy Policy Act of 2005 made major changes in the rules of the game for thepower industry in the United States, including:1.Electric Reliability Organization evolution under FERC (and associated regional

entities) and new mandatory electric reliability standards enforced by FERC;2. DOE Congestion study and National Interest Electric Transmission

Corridors;3. New powers to FERC and the Department of Energy (DOE) on Electric

Transmission expansion and Liquefied Natural Gas (LNG) terminal projects;4. The amendment of PURPA, the Public Utilities Regulatory Policy Act, which

since 1978 has fostered competition in generation by requiring electric utilities topurchase power from Qualifying Facilities (QFs) at the utilities’ avoided cost;

5. The repeal of PUHCA, the Public Utility Holding Company Act, which hasdictated the structure of the U.S. power utility industry since 1935; and

6. The creation of tax incentives and subsidies for renewable, coal, and nucleargeneration, and for electric transmission. Although the bill is now law, it will take

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regulators and others years to fully implement it. Court challenges and debate arenot over.

Where are We Now? A Global Energy Tour of the Regions

WECC

Global Energy continues to see high summer peak reserve margins in the WesternElectricity Coordinating Council (WECC) for the next several years, in part reflective ofthe fact that the hydro rich Northwest has significant excess peaking capacity in summermonths.

Existing WECC generation, combined with capacity under construction and planned forlocal adequacy needs, will bring total installed capacity to 203,595 MW by 2007(including 2,794 MW of interruptible load and wind dependable capacity assumed to be20 percent of nameplate), which is more than enough generation to cover a WECC wide 1-on-2 peak load that is forecast at 150,000 in 2007, and an average load of less than100,000 MW. Further, this capacity reserve should allow suppliers to have plenty ofmargin to cover another peak load excursion caused by extreme temperatures that mightoccur in 2007.

Concerns about local area resource adequacy (and reactions to this summer’s weather-induced high peak loads) have caused several entities to decide to add more new supplyin the next few years than they had planned to add only six months ago. Global Energyhas determined that approximately 10,000 MW more new generation is highly likely tocome on line in the next five years as compared to what we had expected in our Spring2006 WECC report. This 10,000 MW of additional assumed supply brings the totalexpected amount of new generation over the next five years to over 20,000 MW of newsupply, which continues to put downward pressure on spot market power prices.

Figure ES-1 below shows the location of the 20,000 MW of additional new supplies thatGlobal Energy has identified that will be built from 2006-2011.

Figure ES-1Location of New Generation in the WECC; 2006-2010


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SOURCE: Global Energy.

New renewable energy projects are being pursued aggressively by both developers andload serving entities to meet renewable portfolio standards. But, transmission issuescontinue to make it difficult for renewables.

High gas prices continue to encourage development of coal, but environmental concernssurround the cheaper pulverized coal technology. In California, a greenhouse gasemission law has been passed that requires CO2 levels in California to drop to 1990 levelsby 2020. A separate law in California limits the amount of CO2 that can come from newbaseload supply to the CO2 amount that would be emitted by a gas-fired combined cyclecombustion turbine.

Natural gas-fired generation therefore continues to be the technology of choice withnearly 60 percent of new plants built gas-fired. High natural gas storage and theconstruction of the LNG plant in Baja Mexico seem to be ameliorating concerns aboutnatural gas prices. Further, gas turbine technology is seeing improvements in efficiency.The Frame 6 CCCT technology with its improved heat rate is being demonstrated. Therecent commercialization of the LMS100 gas turbine has focused the market on therealization that an operationally flexible, easy to construct, 100 MW simple cycle unit canhave a heat rate of 8,600 Btu/kWh. These units are very attractive in meeting localreliability concerns and may be an alternative to transmission lines that are not popular.

Although the WECC as a whole is a summer peaking region, the Northwest is a winterpeaking region. Over 60 percent of the Northwest resource capability is from hydrogeneration. As a result, the Northwest tends to be more concerned about energy adequacythan peak adequacy because their hydro dams inherently provide large amounts ofgenerating capacity reserves. All or portions of Oregon, Washington, Idaho, Montana,


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Wyoming, Nevada, and Utah comprise the Northwest area along with the Canadianprovinces of British Columbia and Alberta. Oregon, Washington, and western Montanacoordinate the operation of their hydro resources to serve load. WECC hydro resourcesequate to about 29 percent of the WECC’s energy supply in a normal hydro year, but candrop to approximately 20 percent in a severe drought year.

Global Energy’s representation of energy production from hydro facilities located in theWECC region is largely tied to the hydro energy production in the U.S. Pacific Northwest,Canada, and California. In total, these areas account for over 90 percent of the hydrogeneration in the WECC region. For a year with median hydro conditions, annual energyproduction from hydro generation in the WECC region is forecast to be 245,900 GWh.While Global Energy is assuming normal hydro conditions throughout the WECC for theforecast period, volatility in hydro is a fact of life in the WECC and should be consideredin strategic planning of resource additions and the strategic planning of regionaltransmission.

Figure ES-2The WECC Region at a Glance

200,801MW Installed Capacity - July 2007 Peak

61,546MW of Installed Hydro Capacity - July 2007 Peak

133,887MW Thermal Capacity - July 2007 Peak

9,477MW Nuclear Capacity - July 2007 Peak

4,020Pump Storage - July 2007 Peak

150,150MW Forecast Peak Load - July 2007 Peak

35%Reserve Margin - July 2007 Peak

2%Electric Load Growth - 2007- 2011

204,361MW Nameplate Announced New - September 2006

5,901MW Under Construction - September 2006

97,734MW on Hold or Cancelled - September 2006

46,209MW Completed - September 2006


Aside from the significant amount of new generation completed since the end of thepower crisis in June 2001 and additional new plants being brought on line, the mostsignificant issues of relevance to the WECC include the following.

Load Forecast - The record peak loads that occurred in July of 2006 across WECCare widely believed to be caused by abnormal temperature excursions and not anindication of economic growth in the demand for electricity. Performing“temperature normalization” of these record loads appears to bring them in line with


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the forecast of six month ago. Our load forecast remains very similar to the forecastmade in the spring of 2006, which shows about a 2 percent/year load growth.

Retirements - Cumulative retirements of existing resources over the 25-year studyperiod are forecast to be 26,695 MW, little changed from the 26,643 MW retirementsin our Spring 2006 forecast. In the Fall 2006 forecast, Global Energy is assuming thatthe Mohave coal plant is being permanently retired and will not be brought back intoservice during the 25-year forecast period. Global Energy assumes that none of thenuclear plants in WECC will retire in the next 25 years.

Not Enough Renewable Generation under Construction to Meet RPS -Global Energy is including over 20,000 MW of new generation that is currently underconstruction or otherwise highly assured to be built between 2006 and 2011. GlobalEnergy also assumes that additional renewable generation will be constructed in aneffort to meet targets established for energy produced from renewable resources.However, based on Global Energy’s analysis of the expected build out of renewableresources, California will not meet its renewable portfolio standard target of 20percent renewable generation by 2010. Total new generation construction in thisforecast includes approximately 10,000 MW of new capacity by 2011 that was notincluded in the Spring 2006 forecast.

Figure ES-4 shows announced power plants in the WECC and their construction statussince 2000. Since the Spring 2006 report, the completed and under construction capacityhas increased by about 6 percent.

Figure ES-4WECC Power Plant Construction Status

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Delayed or Cancelled

Under ConstructionCompleted


Figures ES-5 and ES-6 illustrate the new capacity additions since 1991 and the status ofannounced power projects in the WECC, respectively.


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Figure ES-5New Capacity in the WECC Region

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1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

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Figure ES-6Status of Announced Projects (MW)

Cancelled/On Hold48%

Completed by 9/06/200624%

Other Announced17%

Under Study1%

Under Construction by 9/06/20063%

Permitted7%

SOURCE: Global Energy EnerPrise Online™.


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Midwest

Like many market regions, the Midwest is growing out of the historic overbuild withreserve margins expected to be 19 percent in 2007—including an additional 3,253 MW ofnew supply currently under construction to be online by August 2007. Between ourSpring 2006 and Fall 2006 forecast updates, Global Energy identified an additional2,600 MW of coal-fired additions and 1,700 MW of renewables that is likely to come intooperation by 2012.

Over 92,700 MW of new generating capacity will have entered the Midwest marketsbetween 2000 and 2012. This is a significant amount of new capacity in an area with anexpected annual peak load of 318,546 MW in 2007. Much of this new generation isnatural gas-fired generation that has been constructed in the vicinity of load centers (seeFigure ES-1 for a detailed view).

Over 12,400 MW of this capacity is located in Illinois, over 9,100 MW in Pennsylvania,and approximately 8,000 MW in Ohio. Although much of the new capacity is located nearmajor population centers, there are still some localized supply/transmission concerns dueto the concentration of these new efficient additions in certain areas stressing thetransmission system. As a result, transmission congestion has become an issue in theMidwest, demonstrated by the increase in Transmission Loading Relief (TLR) eventsreaching nearly 1,300 occurrences in Midwest ISO (MISO) alone during both of 2004 and2005, up from only 20 in 2001.

Figure ES-1Location of New Generation in the Midwest



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Despite the considerable amount of recent capacity additions and the resulting highreserve margins, the Midwest markets appear to be growing out of the overbuild situationsooner than expected. Reliability concerns have reoccurred during this past summerwhen extremely high summer temperatures led to record breaking peak loads across theMidwest. Between July 17 and August 17 of 2006, prolonged heat waves sent electricityusage in MISO, PJM, and SPP to record-breaking levels at least twice, reaching levels notexpected until 2008-2010. This represented a 4 to 8 percent increase from 2005 recordpeak loads. Through calls for conservation, emergency procedures, coordinated plantmaintenance planning, and demand response programs, regional grid operatorssuccessfully coped with the repercussions of this summer’s heat wave.

The North America Reliability Council (NERC) and the Federal Energy RegulatoryCommission (FERC) commended the bulk power system for its ability to apply thelessons learned from the August 2003 blackout and successfully meet customer demand,barring some localized shortages. At the same time, both NERC and FERC stressed theneed for improving grid performance in the future through higher reserve margins,improved transmission siting policies, generation development, and enhanced demandresponse programs.

High gas prices continue to encourage development of coal, but environmental concernssurround the cheaper pulverized coal technology. Beyond the next few years, we have nowincluded about 45,500 MW of new coal-fired capacity that will be added in the latter halfof the forecast period.5 Although we have extended the operating licenses of nearly allnuclear plants, we have not assumed new nuclear entry will occur.

Many states in the Midwest have established targets for generation by renewable supplyresources. To fully meet these targets, significant amounts of new renewables will need tobe built. The extended federal tax credits under the recently signed Energy Bill are nowexpected to spur nationwide growth in renewables activities. At the same time, it isbecoming more and more obvious that new renewables will require new transmissionlines. In the Midwest, regional transmission expansion planning incorporatestransmission capacity upgrades that would allow the cheap renewable generation to reachload centers. The Midwest ISO’s (MISO) transmission expansion plan promotes theaddition of more renewable capacity in the medium term. In addition to the recentadditions and units currently under construction, we have assumed that additionalrenewable capacity will enter the Midwest markets between 2008 and 2020 incompliance with Renewable Portfolio Standards (RPS) requirements in ten Midwesternstates. In total, about 21,800 MW of generic renewables are being added over the forecasttime frame. However, transmission issues continue to make it difficult for renewablegeneration.

5 In addition, we include about 19,500 MW coal-fired additions to repower older coalcapacity that retires during the study period.


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Due to transmission, siting, and environmental issues facing other technologies, naturalgas-fired generation remains the technology of choice with 58 percent of the generic long-term capacity additions gas-fired.

Planning reserve margins are currently still high in several Midwest market zones. Ouranalysis has indicated that there are around six market areas that have reserve marginsabove 25 percent in 2007. Examples of these significantly overbuilt areas include AEP,APS, Dakotas, and Entergy. However, as mentioned earlier, the Midwest markets aregrowing out of the capacity surplus at a faster than expected rate. By the end of thisdecade, seven market areas in the Midwest will require additional capacity to maintaintheir planning reserve targets. SPPN, ALTW, MECS, Minnesota, and Cinergy are amongthese areas. In our Fall 2006 analysis, Global Energy expects peak load forecast for 2007to be 318,546 MW—slightly lower than forecast in the Spring 2006 report. This reductionreflects the overall view of utilities and Load Serving Entities’ (LSE) peak load obligationbased on recent filings. The reduction possibly reflects an anticipation of reduced demanddue to higher fuel and resulting electricity prices.

Figure ES-3The Midwest Region at a Glance

379,513MW Total Installed Capacity - August 2007

21,506MW of Installed Hydro Capacity - August 2007

179,580MW of Installed Coal Capacity - August 2007

318,546MW Forecast Peak Load - August 2007

19%Reserve Margin - August 2007

1.48%Load Growth

264,051MW Announced Development - October 2006

7,437MW Under Construction - October 2006

140,067MW Already Cancelled - October 2006


Figure ES-4 shows announced power capacity in the Midwest and its construction statussince 2000. While delayed and canceled plants have somewhat stabilized, there remainsabout 46,000 MW of “planned” capacity additions still in development.


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Merchant generator profitability continues to be problematic where the overbuildpersists. The large amounts of new supply and low wholesale prices in the past havecaused spark spreads for gas-fired generation in the last two years to be lower than thelevels sufficient to provide decent financial results.6 In the Midwest, merchant gasgenerators are affected by the preponderance of coal and nuclear generation.Notwithstanding the high reserve margins and overbuild, this competition between gas-and solid-fueled plants has exacerbated the competitive struggle facing the Midwestmerchant gas sector.

Further, some of the new plants find themselves on the wrong side of congestedtransmission lines. However, as the electricity markets of the Midwest graduallyreemerge from the historic overbuild, the markets show some signs of recovery withmarket heat rates elevated from their low 2004 and 2005 levels. This trend is expected tocontinue during the first few years, offering improved value for merchant generators.

Figures ES-5 and ES-6 illustrate the new capacity additions since 2000 and the fuel mixof announced power projects in the Midwest, respectively. As shown in Figure ES-5,development activity in the Midwest markets indicates that the free fall from the peakyear of 2002 has come to an end. Between 2007 and 2015, developers plan to add another48,000 MW of generating capacity. As demonstrated in Figure ES-6, these additions nowsuggest a more balanced resource mix as opposed to the recent building boom with agreater presence of coal, nuclear, and renewable fuels inspired among other things by thegrowing volatility in the natural gas markets.

Figure ES-5New Capacity in the Midwest Region

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6 This continues to be true despite the fact that higher natural gas prices have providedimproved on-peak spark spreads for new, highly efficient gas-fired generation.


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Figure ES-6Announced Capacity Fuel Mix in the Midwest

Gas17%

Renewables and Other8%Hydro

4%

Coal60%

Nuclear11%

SOURCE: Global Energy’s EnerPrise Online.™

The past six months have witnessed some major developments in the Midwest markets.MISO locational marginal price (LMP) based energy markets have now been operatingfor over 18 months. While the RTO has been commended for successful and smoothtransition and operation, several member utilities have expressed concerns about highcosts associated with participating in the energy markets and threatened to withdrawfrom MISO. In the lead were LG&E Energy’s subsidiaries, LG&E and KU, who abandonedMISO for an independent transmission operator (ITO) plan, with the Southwest PowerPool (SPP) as the ITO and TVA the reliability coordinator. Concurrently, FERC hasfinalized an order allowing for a more transparent cost and revenue reporting by the RTOand their member utilities.

The major concern for regulators and MISO members has been the revenue sufficiencyguarantee (RSG) charges—used by MISO to allocate costs among its participants. FERCculminated deliberations on this issue with an April 2006 order ruling that MISO hadbeen violating its transmission and energy market tariff (TEMT)—since the inception ofits energy market in April 2005—by excluding virtual supply offers from its calculation ofthe RSG charges. MISO was therefore ordered to include virtual transactions in its futurecost allocation calculations. MISO and several of its members are concerned that suchruling would result in a reduction of virtual trading activity in the MISO energy markets.

The Midwest RTOs opted for different approaches to ensuring regional resourceadequacy. MISO is designing a spot market mechanism to encourage capacitydevelopment and highlight the value of operating reserve and demand-side managementand fostering long-term contracts. The PJM Interconnection (PJM) proposed ReliabilityPricing Model (RPM) would replace the current Capacity Credit market. The RPM willestablish a locational Installed Capacity (ICAP) market that will have a three-yearplanning horizon and a sloping demand curve and has faced significant opposition mainlyfrom state regulators, load-serving entities, and customers who believe it would raiseconsumer costs and is a windfall for generators. PJM and its generators believe that RPM


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would provide locational incentives for investment in transmission and generationadditions. PJM recently filed a widely accepted settlement agreement with plans toconduct the first RPM auction in April 2007. The settlement agreement includes a lowervalue for capacity than originally proposed at all reserve margin levels.

SPP has delayed its locational energy imbalance service (EIS) market for the sixth timesince last year. FERC has repeatedly expressed concerns about the incompleteness ofSPP’s market design and the need for several modifications. In October, the RTO statedthat it had decided to push the implementation of the market by two months to February2007 in order to complete its assessment and testing of the required systems.

FERC’s approval of Entergy’s Independent Coordinator of Transmission (ICT) proposalhas instigated an interesting phenomenon in the eastern markets. Transmission owningentities that are reluctant to give up control of their transmission assets to fullyfunctioning RTOs have become encouraged to adopt similar plans to satisfy therequirements of Order 2000. Under the ICT plan, the utility would maintain ownershipand control of its transmission assets while the ICT (in Entergy’s case, SPP) wouldoversee and administer the transmission system insuring non-discriminatory access. SPPis expected to begin providing ICT services to Entergy under a four-year term byNovember 25, 2006. In December 2005, FERC approved similar plans filed by Duke(MISO as an ICT) and MidAmerican. MidAmerican began receiving transmission systemcoordinator (TSC) services from TranServ on September 1. Duke’s plan is scheduled tocommence in November. As mentioned earlier, SPP also began providing similar (ITO)services to LG&E on September 1.

Southeast

Most Southeast markets have high levels of generating reserve margins—yet new supplyresources are still being added. In the Fall 2006 forecast, Global Energy identified 15,700MW of generation likely to begin operation by 2012. Over 87,000 MW of new capacitywill have entered the Southeast markets between 2000 and 2011. This is a significantamount of new generation for the Southeast system with an annual peak load of 231,289MW expected in 2007. Much of this new generation is natural gas-fired generation thathas been constructed in the vicinity of load centers (see Figure ES-1 for a detailed view).

About 15,700 MW of this generating capacity is in Florida, 12,100 MW in Georgia, and9,400 MW in Mississippi. Much of the rest of the new generation is located near majorpopulation centers across the Southeast. This high level of capacity additions hasincreased transmission congestion in the Southeast. The new additions has increasedtransmission flows in areas not considered in previous transmission plans resulting in anincreased reliance on transmission loading relief (TLR) measures during the past fewyears. In the SERC Reliability Corporation (SERC) region 238 TLRs were called in 2004,428 in 2005, and 316 in 2006 through September.


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Figure ES-1Location of New Generation in the Southeast


High gas prices continue to encourage development of coal, but environmental concernssurround the cheaper pulverized coal technology. Beyond the current building boom andwell into the future, Global Energy has reviewed resource build out and made severaladjustments. In our Fall 2006 forecast, we include about 19,000 MW of long-termgeneric coal-fired capacity that will be added in the latter half of the forecast period.7

Although we have extended the operating licenses of nearly all nuclear plants, we havenot assumed new nuclear entry will occur. Most of the remainder of the resourceadditions is gas-fired.

Outside of the Southeast region, many states and municipals have established targets forrenewable supply sources—or Renewable Portfolio Standards (RPS). In the Southeast,only one Florida utility has adopted a renewable generation target. The Florida PublicService Commission (FPSC) has taken steps to expand the opportunities for alternativesources of electricity. The inactivity in this area in the rest of the Southeast is due toseveral factors including relatively poor wind regimes present in the region and theregulated vertically integrated utility nature of the markets.

Global Energy’s Fall 2006 Southeast forecast includes a very small amount of underconstruction renewable capacity. However, there are around 600 MW of renewablecapacity being developed in the Southeast that may begin construction in the near future.

7 In addition, we include about 11,500 MW coal-fired additions to repower older coal-firedcapacity that retires during the study period.


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Beyond the next few years, we have assumed that renewable supply will be built at aboutthe same rate as has been recently added in the Southeast. Global Energy has assumed inits Fall 2006 forecast that utilities would build another 4,600 MW of renewablegenerating capacity between 2010 and 2030. Even with these assumed additions,renewable capacity including hydro units will only meet 3 to 4 percent of the Southeastenergy needs by the end of the forecast period. Gas-fired generation continues to be thetechnology of choice, as reflected by the fact that 78 percent of the generic long-termcapacity additions is gas-fired.

Figure ES-2Historical Henry Hub Spot Prices

-

2

4

6

8

10

12

14

16

18

20

Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06

$/M

MB

tu

Thin Storage

Mild Weather

Energy Crisis/ Market manipulation

Storage Fears

Hurricane Lili

Weather EventPerception of shortsupply / CrudeSympathy

Hurricane Ivan

Hurricanes Katrina and Rita

Expectation ofa Cold Winterand ThinSupply

SOURCE: Global Energy, NGI.

Planning reserve margins are currently very high across most Southeast market zones.Our analysis has indicated that reserve margins in SOCO, Entergy, and TVA will remainat or above 20 percent through 2010. By the end of this decade, only AECI would requireadditional capacity to maintain its planning reserve targets.

The Southeast region, as modeled by Global Energy, extends across all or portions of 13states. Figure ES-3 presents a snapshot of the Southeast region. In our Fall 2006 analysis,Global Energy’s peak load forecast for the Southeast market in 2007 is 231,289 MW.


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Figure ES-3The Southeast Region at a Glance

292,200MW Installed Capacity - August 2007

21,358MW Installed Hydro Capacity - August 2007

96,860MW Installed Coal Capacity - August 2007

231,289MW Forecast Peak Load - August 2007

26%Reserve Margin - August 2007

1.87%Electric Load Growth

225,621MW Announced Development - October 2006

4,895MW Under Construction - October 2006

114,734MW Already Cancelled or on Hold - October 2006


Figure ES-4 shows announced generating capacity in the Southeast and its constructionstatus since 2000.

Figure ES-4Project Status since January 2000

-150,000

-100,000

-50,000

0

50,000

100,000

150,000

200,000

2000 2001 2002 2003 2004 2005 2006

Gen

erat

ing

Cap

acity

(MW

)

Pre-ConstructionDevelopment

Under Constr.Completed

Delayed orCancelled

SOURCE: Global Energy EnerPrise Online.™


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Merchant generator profitability continues to be problematic. The large amounts of newsupply and low wholesale prices have caused spark spreads for gas-fired generation in thelast few years to be lower than the levels sufficient to provide decent financial results.8

Further, many of the new plants find themselves on the wrong side of congestedtransmission lines. In the Fall 2006 forecast, if weather conditions are normal, gas-firedmerchant generation will continue to face financial challenges. However, as the electricitymarkets gradually reemerge from the historic overbuild, they will show signs of recoverywith market heat rates elevated from their low 2004 and 2005 levels. This trend isexpected to continue during the following few years, offering improved value formerchant generators in the region. At the same time, the continuation of high natural gasprices over the next few years is expected to keep spot market prices relatively high sincenatural gas-fired generation is on the margin frequently, especially during on-peaksummer hours.

Figures ES-5 and ES-6 illustrate the new capacity additions since 2000 and the fuel mixof announced power projects in the Southeast, respectively. As shown in Figure ES-5,development activity in the Southeast markets indicates that the free fall from the peakyear of 2002 has come to an end. Between 2007 and 2016, developers plan to addanother 41,000 MW of generating capacity. As demonstrated in Figure ES-6, theseadditions now suggest a more balanced resource mix as opposed to the recent buildingboom with a greater presence of coal and nuclear fuels, inspired among other things bythe growing volatility in the natural gas markets. The presence of renewable capacity isstill limited in the Southeast.

Figure ES-5 illustrates the current status of announced power projects in the Southeast.

Figure ES-5New Capacity in the Southeast Region

0

5,000

10,000

15,000

20,000

25,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016Year

Inst

alle

d C

apac

ity (M

W)

Completed Under Construction Pre-construction Development


8 This continues to be true despite the fact that higher natural gas prices have providedimproved on-peak spark spreads for new, highly efficient gas-fired generation.


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Figure ES-6Announced Capacity Fuel Mix in the Southeast

Nuclear37%

Renewables & Other1%Hydro

1% Gas33%

Coal28%


Recently, the electricity markets have witnessed renewed interest from power plantdevelopers in coal-fired capacity. In the Southeast, there are 1,160 MW that is underconstruction to be on line by 2009. Another 10,100 MW is in different stages ofdevelopment. Figure ES-6 shows the current status of coal plant developments in theSoutheast.

Figure ES-7Coal Plant Development Status

0

2,000

4,000

6,000

8,000

10,000

12,000

2002 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013Year

Cum

ulat

ive

Add

ition

s Su

mm

er R

atin

g (M

W)

Completed Under Construction Pre Construction


The Southeast electricity markets continue to be dominated by tight state regulatorauthority and vertically integrated utilities that are responsible for bundled generation,transmission, and distribution services. All efforts towards establishing RegionalTransmission Organizations (RTO) have been halted while other alternatives to openaccess are being installed. Entergy’s proposal of establishing an Independent Coordinatorof Transmission (ICT) to oversee its transmission system has received FERC approvalwith execution expected in November. In April 2006, FERC extended the initial term of


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the ICT to four years, rather than two. The Southwest Power Pool agreed to assume therole of the ICT and was directed by FERC under an October 2006 order to fulfill itsresponsibilities within 30 days. The ICT proposal is largely seen as a step towardsalleviating transmission congestion and allowing non-discriminatory transmission accessto Entergy’s system. Under the ICT plan, Entergy would maintain ownership and controlof its transmission assets while SPP would oversee and administer the transmissionsystem, insuring independent oversight and non-discriminatory access.

FERC’s approval of Entergy’s proposal has encouraged other transmission owningentities that are reluctant to give up control of their transmission assets to fullyfunctioning RTOs to consider similar arrangements to satisfy the requirements of Order2000. In July 2005, Duke proposed its own ICT plan with MISO as its ICT. Also, LG&EEnergy has gained FERC’s approval of the withdrawal of its subsidiaries, LG&E and KU,from MISO to SPP would as its ICT and TVA as its reliability coordinator beginning onSeptember 1, 2006. In September 2006, MidAmerican has begun taking TransmissionSystem Coordinator (TSC) services from TranServ. FERC approved the Duke andMidAmerican ICT plans in December 2005. Duke Energy’s ICT plan will be implementedin November 2006.

Market forces and federal rules are steering another utility in the Southeast towardallowing competitive power access into its transmission system. TVA is faced with at leastsix utilities planning to terminate their contracts with the federal service provider forcompetitive suppliers between 2008 and 2010. In addition, the utility has been asked forthe first time by FERC to provide the required interconnections between one of its exitingmembers and the alternative supplier it had selected. In July 2006, FERC conditionallyapproved a revised Interconnection Agreement between TVA and EKPC and stated thatfailure to comply with its stipulations will expose TVA to civil penalties. As a result, TVAis considering means by which it could enhance its competitiveness as well as provideopen access within its grid.

RTO activity in Florida hit a major roadblock when a cost-benefit analysis on GridFloridaconcluded that the costs of the RTO would outweigh its benefits. Florida utilities haveremained in disagreement about its future. Florida Municipal Power Agency, SeminoleElectric Cooperative, Calpine, and Northern Star Energy proposed a non-RTO alternativefor Florida, the Florida Independent Transmission Provider (FITP). FITP responsibilitieswould include tariff administration, OASIS operation, and coordination of transmissionsystem planning. However, stakeholders were not ready for a new organization and theproposal was shelved. On the other hand, major Florida utilities such as Florida Powerand Light (FP&L), Progress Energy Florida (PEF), and Tampa Electric (TECO) haveformally requested that the GridFlorida docket be closed permanently. This requestreceived support from Florida Municipal Group (FMG). The request for abandonmentwas approved by the FPSC on May 9, 2006, citing the findings of the cost benefit study,which implied that the pursuit of an RTO would be against public interest. In June 2006,the GridFlorida sponsors officially terminated their proposal. The FPSC still remainpositive regarding open competitive markets and encourages continued studies on thefeasibility of opening up its system.


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After more than a year since hurricanes Rita and Katrina caused widespread damage tomajor parts of the natural gas and electricity infrastructure, Entergy is still continuingefforts to rebuild its system. Total restoration costs of $750 million to $1.1 billion wasestimated for the repair and/or replacement of Entergy’s electric and gas facilities. Inaddition to increased stress on its transmission system, the hurricanes brought severefinancial stress to Entergy affiliates. Entergy New Orleans, who filed for bankruptcyprotection in 2005, is still not close to developing a reorganization plan. The amount offederal aid and the New Orleans City Council’s decision on its rate increase proposal willdecide its fate. Entergy is seeking federal funding in the form of Community DevelopmentBlock Grants (CDBG). The states of Louisiana and Mississippi already received $10.4billion and $5.4 billion as part of the federal hurricane aid package and will administerthe funds after proper review of estimated costs.

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The Global Energy Big Picture (2007)

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