Judging by Wednesday’s announcement of a massive generating capacity expansion by NRG Energy and earlier word from TXU Corp. that it will expand coal-fired capacity, natural gas is no longer the darling of power generation developers. It appears gas will be sharing the stage with coal, nuclear and wind, at least based on the industry’s latest plans to expand generating capacity.

Having successfully spurned the unwanted merger advances of Mirant Corp. (see Daily GPI, June 13), NRG Energy is stepping out with an ambitious plan to spend about $16 billion for more than 10,000 MW of new capacity over the next 10 years.

NRG is staying focused on existing operating areas of southern California (CAISO), Texas (ERCOT), Louisiana (SERC) and the Northeast (PJM, NYISO, NE-ISO). Combined with TXU Corp.’s recent announcement that it will sell its Texas gas-fired generation and build 11 new coal-fired plants in the state (see Daily GPI, April 21), Wednesday’s NRG announcement could be heard as the clarion call for the next cycle of power generation construction.

Reserve margins have been growing thinner across the country, and industry executives on the conference circuit have been calling for new construction to start now to meet tomorrow’s demand, particularly since coal and nuclear (the future of generation?) have such long construction lead times. Indeed, signs of the times of high gas prices are the fact that TXU is forsaking Texas gas for coal and the fact that Princeton, NJ-based NRG will be investing in coal, nuclear and wind; however, gas-fired combustion turbines will be used where appropriate.

Coal, nuclear, gas, wind…that sounds like a diverse portfolio of generation resources, which is exactly the opposite of what the last generation build-out gave the energy industry: all gas, nothing but gas. Just as Ford couldn’t keep making black cars exclusively, generation developers are now forced to offer different flavors of power. Obviously, credit high gas prices for this change of heart. But also credit the coal industry for cleaning up its act, at least a little; and greens for opening their minds, at least a little, to the charms of the atom.

“It’s going to be different. It’s going to have to be,” Paul Harmon, R.W. Beck vice president of energy asset consulting, told NGI. How much different this generation build-out is from what happened in the late 1990s-early 2000s remains to be seen. It’s worth noting, though, that this time around similar forces are acting on different players.

Six to eight years ago, merchant generators like Calpine Corp. and AES were the ones touting bold generation construction plans and building plants. Following the crack-up in merchant power, more and more generation on the ground has been finding its way into utility rate base, with more to come. Nobody is building plants on spec anymore. NRG said Wednesday it wants its new plants to have 70% or more of their capacity spoken for at terms of 10 years or greater before any executive picks up a ceremonial shovel. That’s not speculative. And NRG said Wednesday that any merchant portion of its new capacity wouldn’t become uneconomic unless gas prices hit the $4-5 range.

The last time around, an investor mentality drove the generation build-out: Build gas because it’s quick and easy to permit; site it where it’s convenient, and the customers will come. “Some really good, smart companies put some plants in some really bad places, and you wonder why,” Harmon said.

High gas prices and the long lead times required for coal and nuclear surely will instill more discipline in developers. But will it be enough?

“I’m not sure we can get past that investor mentality, that short-term investor mentality,” Harmon said. “If you’re not going to have something on line for 10 years, what’s the market going to be like then? We’ve got people uncomfortable with what it’s going to be like next year.

“It’s interesting that when we overbuilt the gas plants, the [construction] cycle time is shorter there. We kind of figured that out a couple years after we overbuilt in some areas. The problem with coal is it’s such a long-term play, nuclear as well. You’re not going to know you’re overbuilt [until] you’ve got about 10 projects half-built that you don’t need, kind of like we did in the ’80s. The longer-term planning makes a big difference, and more money.”

And speaking of money, NRG said it will be seeking co-owners and third-party investment from equity investors, offtakers and equipment suppliers to support its projects. Project financing will be used to reduce NRG exposure and maintain balance sheet ratios. Projects are expected to attract debt with minimum terms of seven to 10 years, with longer terms likely available. Much of the debt will be on balance sheet but off credit.

Overall NRG’s construction plans are intended to:

“NRG is strategically located in domestic markets with high and growing demand for power and an over-reliance on expensive natural gas for their power generation,” said NRG CEO David Crane. “NRG’s development program is designed to meet the growing energy needs of these regions, while both reducing their dependence on natural gas for power generation purposes and making meaningful progress towards reducing our carbon profile.

“Our proposed mix of baseload plants — involving two nuclear units, three gasified coal units, two traditional pulverized coal units with full back-end controls, at least one modern combined-cycle plant and at least two wind farms — will substantially reduce the carbon intensity of NRG’s existing baseload fleet, in particular, and of the nation’s baseload coal alternative, in general.”

“Consistent with NRG’s track record of financial discipline and capital allocation, the financing plan for these projects preserves NRG’s balance sheet strength and liquidity,” said NRG CFO Robert Flexon. “Investments will be underpinned by long-term offtake contracts and hedges that support nonrecourse project financing as well as third-party equity partners and the Company’s existing cash flows.”

Given the size, capital intensity and long development time for many of these new plants, particularly the baseload plants, NRG said it intends to contract at least 70% of its new output through power purchase agreements, bilateral contracts or hedges with financial firms. NRG’s plants are located in regions that currently have significant opportunities for long-term offtake agreements. For example, in the Northeast, request for proposals for power purchases have been announced or authorized in Connecticut, Delaware and New York; and bilateral contracts for wholesale power are being pursued by cooperatives, municipalities, investor-owned utilities and large industrials in California, Louisiana, and Texas. As an example, NRG has secured a significant power purchase agreement with the South Mississippi Electric Power Association (SMEPA) for 75 MW for 4.5 years that will carry them until Big Cajun (BC) II unit 4 goes commercial, at which time they will take equity (and the associated output) in the BC II unit 4 project.

NRG said Tuesday it agreed to acquire privately held Padoma Wind Power LLC, a wind energy development and co-development company.

Texas’s demand growth is among the strongest in the nation and in order to ensure the reliability of electrical service in the region, new plant construction is essential. NRG’s development plan incorporates multiple technologies including gas peakers, pulverized coal and nuclear power. Each new plant’s permitting and construction schedule varies, enabling NRG to meet expected demand growth as it develops.

NRG’s repowering plan for Texas contemplates adding 3,500 MW of new baseload capacity using both coal and nuclear fuel, as well as 500 MW of more efficient, gas-fired peaking and intermediate capacity to serve particularly high-demand, capacity-constrained areas around Houston. NRG also anticipates building wind facilities in Texas as part of the Padoma development portfolio.

This month NRG filed with the Nuclear Regulatory Commission for 2,700 MW of nuclear power at the existing South Texas Project (STP) facility. It also filed an air permit with the Texas Commission on Environmental Quality (TCEQ) for Limestone 3, a new 800 MW pulverized coal unit. Also this month, the company filed another air permit application with TCEQ for uprating of two W.A. Parish coal units by about 100 MW by 2010. And at the beginning of May, NRG expressed its support for the FutureGen Industrial Alliance. One of two Texas sites proposed for the FutureGen integrated gasification combined cycle test unit would be on NRG-donated property near its Limestone plant.

Construction of Units 3 and 4 at the South Texas Project is expected to cost $5.2 billion.

“Nuclear power is an important part of the continued development of our baseload fleet in Texas,” said Steven Winn, president of NRG’s Texas region. “We recognize the need for new, low-cost generation and we recognize the importance of reducing the emissions profile of power generators within the growing ERCOT [Electric Reliability Council of Texas] market.”

NRG said it expects to invest $1.2 billion to construct the new unit at Limestone. With prompt approval of the permit the unit could be online by 2012. NRG anticipates that offtake for Limestone will be covered through a blend of bilateral negotiated contracts with local municipalities, industrials and co-ops as well as use of more market-based hedge instruments. NRG is currently in negotiations with a range of potential offtakers.

NRG said it intends to file in August a multi-site permit application to begin to update its Houston-based gas generation fleet. New, more efficient gas units will be added to replace existing capacity. The new fast-start units will provide better grid support within the Houston zone. These units should provide additional support for periods of high electricity demand and produce a net reduction in emissions per MWh. The anticipated total increase in capacity is approximately 500 MW.

Since 1999, NRG and its predecessor companies have spent more than $700 million to add emissions control technologies to its existing generation fleet in Texas. This has resulted in a net reduction in nitrogen oxide (NOx) emissions of 75%.

NRG’s Northeast redevelopment plan calls for the addition of 2,250 MW of new baseload capacity using IGCC technology and 840 MW of new, dual-fuel oil and gas-fired intermediate and peaking capacity to serve particularly high-demand, capacity-constrained areas, such as New York City and southwest Connecticut. As part of this plan, NRG expects to retire 968 net MW of less efficient, higher emitting units.

NRG recently completed evaluation of IGCC technology providers and chose a preferred gasification process. The company has begun the permitting process for each of the sites it plans to repower. NRG expects to contract substantially all of its development projects in the Northeast through state administered processes. The contracts will range up to 20 years in length. These processes will commence as early as the fourth quarter of 2006 and are currently anticipated to be completed in the first half of 2007. NRG’s Northeast development plan is expected to result in lower emission rates across the board, including a 59% reduction in SO2, a 49% reduction in NOX, an 84% reduction in mercury, and a 4% reduction in CO2 intensity.

“Virtually all key stakeholders in the Northeast agree that new investment in power plants is needed to address rising and unstable power prices stemming from tightening of supply and demand and an over-reliance on natural gas as a fuel for power generation. This new investment must also address the need to reduce emission levels,” said Curt Morgan, president of the Northeast region.

NRG’s development plan for the South Central region adds 1,000 MW of new baseload capacity. Upon completion of this expansion as well as development projects already under way, NRG will have 2,775 net MW of generating capacity in the South Central region.

The company has agreed to terms with three parties for joint development and co-ownership of BC II Unit 4. SMEPA, East Texas Electric Cooperative and the City of North Little Rock, AR, will collectively own 260 MW of the project. The South Central region will utilize state-of-the-art emissions controls, including selective catalytic reduction (SCR), scrubbers, sorbent injection, and bag houses to meet best available control technology (BACT) requirements. The total cost of this equipment is projected to be approximately $850 million and will generate net emission reductions of approximately 55% for SO2, 40% for NOx, and 70% for mercury while remaining net neutral on NRG’s carbon intensity in the region

“By building coal-fired plants in gas-based markets, NRG will be able to provide consumers with lower-cost, stable and reliable energy solutions,” said John Brewster, president of the company’s South Central region.

The expansion of NRG’s portfolio in the West is predicated on receiving long-term offtake agreements from the incumbent utilities. NRG’s development projects lie inside the Los Angeles and San Diego load pockets. Southern California Edison and SDGE are significantly short on resources and have announced competitive solicitations for new generation. NRG intends to compete in these solicitations.

NRG has allocated $1.5 billion for the West redevelopment plan, which contemplates adding 647 gross MW of new gas-fired baseload capacity and 1,145 gross MW of new gas-fired intermediate and peaking capacity. NRG also anticipates building a new 150 MW wind facility. The company has begun the permitting process for a combined-cycle plant at Encina, CA. The company’s El Segundo, CA site is currently permitted for a 640 MW combined cycle unit. The Long Beach, CA site is in the process of being permitted. NRG is preparing a submittal for a 339 MW peaking facility at the Long Beach site. NRG has adequate emissions offsets to support the new generation at all of the California sites.

“Wind based energy will add another element of diversity to our fuel mix,” said Steve Hoffmann, president of the company’s western region.

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