Jim Asselstine's Bullish Assessment of Nuclear Energy’s Future

Jim Asselstine

The following is a guest post submitted by Scott Peterson, NEI's senior vice president of communications.

SINGAPORE--Jim Asselstine has an unparalleled pedigree to assess the nuclear energy industry. He has analyzed the industry for the past 23 years at Lehman Brothers and Barclays, was a Nuclear Regulatory Commission commissioner and punched his policy credential as a congressional staffer.

“My own personal view is that we should try to keep nuclear power, as the only zero-carbon, large-scale baseload generating source at about its current level of 19 or 20 percent of U.S. [electric] generation,” Asselstine said during a clear-eyed assessment of America’s nuclear energy industry. He was speaking at the World Nuclear Fuel Conference, a global symposium in Singapore sponsored by the Nuclear Energy Institute and World Nuclear Association.

Assuming modest electricity demand growth and with the closure of existing reactors after 60 years of production, Asselstine said meeting this goal would require building 30 to 35 reactors by 2030. Whether the industry builds advanced reactor technology at that pace, he said, depends on these factors:

• Electricity demand must increase with economic rejuvenation.

• Increases in natural gas prices, forecasted by Barclays to move to $3.70 per million Btu by the end of this year, up from $2.82 per million Btu in 2012.

• New Environmental Protection Agency regulations affecting coal-fired power plants, including the announced closure of 25,000 megawatts of coal capacity already and up to 50,000 to 60,000 megawatts of coal capacity by 2015.

• The focused response to the Fukushima accident in Japan both by industry and the NRC. “I regard the NRC requirements and industry initiatives as comprehensive and complementary,” he said.

• Industry and NRC must effectively carry out their responsibilities under a new regulatory framework for building new reactors.

Ironically, Asselstine said this is an exceptional time for energy companies to build large capital projects.

“The industry enjoys broad access to financing at historically attractive rates,” he said. “As a defensive safe haven sector, the electric utilities—unlike many other industries—were able to access the debt capital markets during even the most difficult period in the recession in late 2008 and early 2009. This is an excellent time to finance significant capital investments in the industry.”
It’s appropriate that the industry’s fuel companies are gathering in Singapore. Seventy-one reactors are being built worldwide, with the majority of these projects located in Asia to meet fast-rising electricity demand.

The International Energy Agency predicts that electricity demand will expand by more than 70 percent by 2035, or 2.2 percent per year on average. More than 80 percent of that growth will be in non-OECD countries—more than half in China and India alone.

Growth in China’s electricity demand alone over that period is greater than the total current electricity demand in the United States and Japan combined. China has 26 reactors under construction and the country aims to quadruple its nuclear capacity from reactors now operating and under construction by 2020. India has seven reactors under construction; 20 others are planned. Asselstine said he expects the majority of these projects to be completed despite the 2011 accident in Japan.

On the U.S. response to the Fukushima accident, Asselstine said “the industry and NRC responses have been constructive and timely, and should prove effective in addressing the lessons learned for the industry. The review process helped set priorities for the various recommendations, focusing the agency’s and industry’s efforts on a set of changes that can be implemented relatively quickly to produce substantial near-term safety improvements.”

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Why Nuclear Energy is Critical to American Energy Diversity

Entergy's Bill Mohl

Earlier today, William (Bill) Mohl, President, Energy Wholesale Commodities, Entergy Corporation, testified before the U.S. House Energy and Commerce Committee's Subcommittee on Energy and Power. His testimony was concerned with why it was important for the nation to maintain a diverse portfolio of energy sources. We've excerpted a couple of passages from the speech below (bold emphasis mine):

Another way of looking at the economic value of existing U.S. nuclear generation is to consider the potential cost of replacing it. Based on data publicly available from the U.S. Energy Information Administration, Entergy has calculated that building gas-fired Combined-Cycle Gas Turbine (CCGT) plants to replace the approximately 101,000 megawatts of capacity provided by U.S. nuclear plants would cost between $100 and $110 billion dollars. An investment of this magnitude to replace an existing asset class would be enormous for the U.S. power industry. To provide some perspective, in 2011 U.S. investor-owned utilities (including stand-alone transmission companies) invested slightly more than $30 billion aggregate in transmission and distribution facilities – well under one-third of the low end of the range of the estimated cost that would be required to replace nuclear generation with CCGT plants. Moreover, the $100 billion to $110 billion replacement cost estimate does not include any costs of expanding pipeline capacity to serve new gas-fired plants. The adequacy of pipeline capacity is a key consideration, as was recently demonstrated in New England.

Nuclear power is a crucial contributor to maintaining America’s air quality. Nuclear generation produces virtually no carbon emissions. Since 1995, U.S. nuclear plants have prevented the release of more than 11 billion metric tons of carbon dioxide into the atmosphere. Renewable energy sources can contribute to environmental sustainability, and should be considered for inclusion in a generation portfolio, taking account of emissions, cost, operating characteristics, land use, and other factors. Clean-coal technology shows promise but is not yet as cost-effective as existing nuclear as a source of baseload power. As reliable sources of baseload generation, nuclear plants provide a foundation in the power supply portfolio to support emerging wind and solar power projects, which are characterized by intermittent availability.

A few weeks ago, NEI's Richard Myers took note of some local market conditions in New England that clearly contradicted the conventional wisdom that American is awash in cheap natural gas, a topic that Energy's Bill Mohl also touched on this morning:

Bill Mohl testifies before the Energy and Power Subcommittee.

Earlier in my testimony I noted that nuclear and coal traditionally were the primary fuels used to provide baseload power in the United States. Over the last ten years, improvements in power plant technology coupled with recent low gas prices have created the opportunity to operate CCGTs as baseload units as well. While there are benefits to being able to operate CCGTs as baseload, diversification is a prudent strategy for a generation portfolio, just as it is for an investment portfolio. Sound utility resource planning practices suggest that “you don’t want to put all your eggs in one basket.” In addition to its other benefits, nuclear generation provides a valuable hedge for electric consumers against potential gas price volatility.

Aside from price concerns, there are also challenges presented by the existing pipeline infrastructure and its ability to meet rising demand, particularly in certain regions of the country such as New England.

Again, as our own Richard Myers mentioned, the spot price of natural gas in the Northeast at the end of January was anything but cheap:

Mohl continued:

Consider that replacing all U.S. nuclear units with gas-fired generation would require an additional 14.5 billion cubic feet per day of additional gas supply, a 70% increase over the 20.8 billion cubic feet per day of gas that electric generators used in 2011. Natural gas fired generators do not have on-site fuel inventory and must be continuously supplied through a pipeline system, and while some facilities may have access to gas storage facilities to ensure continuous supply, many facilities do not. Supply issues can arise during peak times, when pipeline capacity is needed to satisfy the demands of local gas distribution companies to serve homes and businesses, in addition to the needs of power plants that may not have contracts for firm delivery. By contrast, nuclear plants have up to eighteen months of fuel supply on site and do not compete with residential and business consumers for fuel, making nuclear plants far less likely to be affected by fuel supply interruptions.

[...]

In summary, every source of energy has advantages and disadvantages. We know this to be true in transportation, home heating and also with electricity. Each generation source varies in terms of cost, economic and environmental impact, and other factors that complement and may be weighed against each other. Generation diversity is simply necessary to ensure a reliable and secure generation portfolio for the nation.

Plenty of interesting facts to keep in mind. We'll share a link to the full text of the testimony once it's posted to the NEI website.

UPDATE: The complete video archive of the hearing has been posted to YouTube:



Finally, click here for a complete transcript of today's testimony.

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The Future in Miniature with Georgia Power

Miniature not because Georgia Power is a small provider of electricity, but because the company’s view of its own future may provide some insight into larger energy trends. We should not assume this to be true, an easy trap to fall into; instead, let’s look at it as one data point in a thesis that could be proven or disproven by more data points.

The reason we can glimpse into the future is because the Georgia Public Service Commission requires Georgia Power to submit what it calls an integrated resource plan. This IRP provides a look at the electricity landscape over the next 20 years. Georgia Power prepares a new IRP every three years, so its outlook can change based on changes in the marketplace.

Although we often refer to the two new reactors at Georgia’s Plant Vogtle as a Southern Co. project, the facility is jointly owned by Georgia Power (45.7%), Oglethorpe Power Corporation (30%), Municipal Electric Authority of Georgia (22.7%) and Dalton Utilities (1.6%). Georgia Power is a subsidiary of Southern Co. and, as you can see, owns the largest share of Plant Vogtle.

But nuclear later. First, coal (and oil): 

As part of today's filing, Georgia Power is requesting to decertify and retire 15 coal- and oil-fired generating units totaling 2,061 megawatts (MW): Units 3 and 4 at Plant Branch in Putnam County; units 1-5 at Plant Yates in Coweta County; units 1 and 2 at Plant McManus in Glynn County; and units 1-4 at Plant Kraft in Chatham County; and Boulevard units 2 and 3, also in Chatham County. In addition, the company is requesting to decertify and sell Plant Bowen Unit 6, which has a rating of 32 MW, bringing the total of retired capacity to 2,093 MW.

I don’t think the company links these closures explicitly to the two new reactors at Vogtle, but consider:

As recently as a year ago, Georgia Power and its parent, Atlanta-based Southern Co., complained about new environmental regulations to reduce toxic emissions from power plants, saying those rules could force the utility to close several coal plants and threaten peak capacity. Company officials said that is no longer a concern because long-term demand is not as high as they once predicted.

And:

Once a dominant fuel for electricity generation, coal’s use will continue to diminish as Georgia Power closes more than a dozen coal and oil-fired units.

And that’s because they do not expect to open any new coal-fired units to replace the closed units.

How about natural gas?

Also, Georgia Power will request converting units 6 and 7 at Plant Yates from coal to natural gas, and will switch from burning Central Appalachian coal to burning Powder River Basin coal at Plant McIntosh Unit 1, pending a successful test burn and further study.

So two more units will halve their carbon emissions. I have no idea of the implications of changing coal type at McIntosh – I’ll leave that to black rock mavens to explain – though I reckon it is meant to improve the facility’s emissions profile.

So no new coal units, a switch of two units to natural gas – and nuclear energy? Well, the story about the filing mentions it only in passing, so let’s tell that part of the story ourselves: the two new reactors will pack about 2234 megawatts capacity. Hmm – coal out, about 2061 megawatts, nuclear in, about 2234. Seems pretty quid pro quo to me, at least as a correlation.

The switchover to natural gas, the build out of nuclear energy, the development of renewable energy sources – Georgia Power expects to field 1500 megawatts of capacity by 2016 – suggests a rapidly changing, environmentally aware and nuclear-friendly energy portfolio. Just to put a cherry on it, let’s add this to our data points:

The continuing expansion of renewable energy technologies, advances in energy efficiency, and the rapid shift from coal to natural gas for generating electricity combined to bring down U.S. carbon dioxide emissions last year to their lowest levels since 1994, according to a report by Bloomberg New Energy Finance. 

And it’s only going to get better when the new reactors in Georgia (and South Carolina) go online later this decade. Still, it’s all good – in miniature or life size.

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NEI's Richard Myers on the Wall Street Journal Story on Natural Gas and Nuclear Energy

NEI VP Richard J. Myers

The following statement concerning today's story on nuclear energy and natural gas ("Can gas undo nuclear power?") that appeared in the Wall Street Journal can be attributed to Richard J. Myers, NEI's Vice President, Policy Development, Planning and Supplier Programs:

Electricity production issues are not quite as cut-and-dried as portrayed in the article, certainly not from the vantage point of energy companies who must evaluate an array of factors to determine what their future generating mix will and will not be. A nuclear energy facility produces benefits well beyond the electricity it generates. They include economic benefits like jobs, taxes and procurement; grid reliability benefits in the form of voltage support and ancillary services; the environmental benefit of avoided emissions; and the energy security benefits of an electricity source that adds diversity and forward price stability to the electricity supply portfolio.

It also bears noting that extremely low natural gas prices in the United States are not sustainable. Low natural gas prices are caused by a combination of reduced demand for natural gas (due to subpar economic growth), abnormally mild weather for the past several winters and a major increase in supply (due to improved drilling techniques that have unlocked vast reserves of shale gas). As the result of low gas prices, producers of natural gas have already slowed drilling: the number of rigs drilling for natural gas in the United States has dropped approximately 50 percent in the past 12 months. At the same time, the historic volatility of natural gas prices continues to be seen in the spot market. Just last week, natural gas prices in New England and New York City topped $30 per million BTUs, the highest level seen this winter, according to the U.S. Energy Information Administration. For New England, this was actually the highest level seen since January 2004.

Judgments about the viability of any given nuclear power plant are business decisions made by individual utilities based on economic circumstances unique to the facility. The Nuclear Energy Institute’s long-term belief is that, beyond the ongoing construction of five reactors in Georgia, South Carolina and Tennessee, new nuclear energy facilities will be built once electricity demand rebounds. Demand for electricity in the United States has not yet returned to the level seen in 2007, before the financial crisis.

For those who might have missed it, here's a table from the Energy Information Administration's Northeastern Winter Natural Gas and Electricity Alert that highlights those dizzying spot prices Richard referenced in his response.

For our earlier post on the story, click here.

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Some Thoughts on the Wall Street Journal Story on Natural Gas and Nuclear Energy

Cheap gas? Not last week in the Northeast.

Yesterday evening, the Wall Street Journal published a story by Rebecca Smith that asked the question, "Can Gas Undo Nuclear Power?" It's a question that's been asked often, especially in the wake of the announced closing of the Kewaunee Power Station in Wisconsin by Dominion last October. Here's what NEI's Richard Myers had to say about it at the time:

In 2005, when Dominion bought the plant: (1) power prices in the Midwest were in the $40-50/MWhr range; wellhead gas prices were in the $6-10 per million Btu range; and U.S. electricity demand was growing.

Today: (1) power prices in the Midwest are in the $30/MWhr range: gas prices are in the $2-3 per million Btu range; and (3) the U.S. has had 5 years of no growth in electricity demand, thanks to the worst recession in 80 years.

Near the close of 2012, NEI's President and CEO, Marv Fertel addressed the natural gas issue head on when it came to building new nuclear energy facilities. The following exchange with Steve Dolley of Platts came during an NEI-sponsored press briefing that took place in December (page 12):

Steve Dolley, Platts: Thanks Marvin, thanks for taking the time today. If you’re not expecting any new plants to be built over the next five or ten years, what are the industries other priorities with the nuclear regulatory commission? I know obviously plant safety is the number one priority for the industry and for NRC, but specific things that you’re hoping to accomplish with the commission over the next year?

Marv Fertel: Well first of all, news flash, we are building four. And we’re finishing Watts Bar, so there’s five new plants both in the pipeline being build. And one of the reasons on new plants, I don’t see us completing any beyond those five in the next - the rest of this decade. [A]s a nation we have not gotten back to 2007 electricity demand rates yet. So our demand is still down. We’re still in this recession. If you go over to financial whatever, we’ve probably increased the recession duration for a while.

So we need demand to come back. And as you all know because of the shale gas game changer (type) situation, we’re seeing low gas prices and low electricity prices right now. So everybody is looking to gas.

I would expect late this decade like into 2020 after we finish Vogtle and Summer that you could see new plants get started in our country. They just won’t be completed this decade. I expect demand will go up and there’s no question the price for natural gas will go up. I don’t expect it’s going to go to $12 or $14, but it will go up. It’s not going to stay at $2 or $3, it’s not even in the futures right now it’s almost $4 next year.

So we’ll see gas go up.

The message here ought to be pretty clear: while natural gas prices are at historic lows today, that can't last forever, especially if, as projected, America begins to export shale gas to international markets. In addition, we're already seeing evidence that industries that rely on natural gas as a feedstock that fled the U.S. during periods of high prices are now returning, driving additional new demand.

Finally, we need to remember that even in times of plenty, the price of natural gas can be awfully volatile. Just a few days ago during a cold snap in the Northeast, day ahead spot prices for natural gas reached $34.25 per MMBtu in New England and $36.00 in New York City.

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NEI Energy Markets Report (October 8-12, 2012)

Here's a snippet of what went on in the energy markets last week:

Electricity peak prices rose slightly last week at ERCOT and Palo Verde, averaging $32-34/MWh at those hubs. Meanwhile at the Northeast, PJM, and Southwest hubs, prices fell $2, $6, and $11, respectively, to average $38-39/MWh. Gas at the Henry Hub rose 12 cents during the week, averaging $3.38/MMBtu. “Faced with softening fall demand fundamentals, power prices for next day delivery worked mostly lower across the U.S. on Thursday, Oct. 11, even as traders looked to rising natural gas prices and climbing outages. ... Cash gas markets also worked higher, adding as much as 15 cents in parts of the West and as much as 25 cents in the East, which offered direct support to power markets. Also lending support, various generating units continue to drop offline, and the outages will accelerate in the coming weeks as units shutter operations for fall maintenance and refueling. ... Several more outages lie around the corner. According to private sources, five nuclear reactors could shut in the next week: SCANA Corp.'s V.C. Summer in South Carolina, Nebraska Public Power District's Cooper plant in Nebraska, Public Service Enterprise Group Inc.'s Salem 2 in New Jersey, Exelon Corp.'s Braidwood 2 in Illinois and Entergy Corp.'s Waterford 3 in Louisiana.” (SNL Energy’s Power Daily – 10/12/12)

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Last week’s uranium spot prices were unchanged, according to Ux Consulting, but TradeTech reported a $2.25 drop to an average $43.50/lb U3O8. “Bearish sentiment gripped the spot uranium market this week and the spot uranium price fell dramatically, losing more than 5 percent over the course of this week. Seven transactions totaling approximately 800 thousand pounds U3O8 are reported for the week. Reasons for the bearish outlook among sellers are varied, but the driving force is clearly a pessimistic view about near-term spot demand from both discretionary and ‘have-to’ buyers. The drop in prices failed to stimulate significant buying interest, and instead caused buyers to pull away from the market in anticipation of further price declines.” (TradeTech’s Nuclear Market Review – 10/12/12)

For more of the report click here.

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NEI Energy Markets Report (October 1-5, 2012)

Here's a snippet of what went on in the energy markets last week:

Electricity peak prices fell slightly last week at ERCOT and Palo Verde, averaging $32/MWh at those hubs. Meanwhile at the Northeast and PJM hubs, prices rose $7 to average $40 and $45/MWh, respectively. “Next-day power markets were mixed to conclude the first week of the new month Friday, Oct. 5, as traders looked to cover short positions ahead of the impending weekend but also with choppy demand outlooks and recent ho-hum moves for natural gas also coming into play.” (SNL Energy’s Power Daily – 10/8/12)

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West Texas Intermediate crude oil fell 54 cents to average $90.81/bbl last week. “EIA projects average household expenditures for heating oil and natural gas will increase by 19 percent and 15 percent, respectively, this winter (October 1 through March 31) compared with last winter. Projected household expenditures are 5 percent higher for electricity and 13 percent higher for propane this winter. Average expenditures for households that heat with heating oil are forecast to be higher than any previous winter on record. The forecast for higher household expenditures primarily reflects a return to roughly normal winter temperatures east of the Rocky Mountains compared with last winter's unusual warmth.” (EIA’s Short-Term Energy and Winter Fuels Outlook – 10/10/12)

For more of the report click here.

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NEI Energy Markets Report (September 24-28, 2012)

Here's a snippet of what went on in the energy markets last week:

Electricity peak prices rose across the country last week, except at the Northeast hub, where they fell $8/MWh. “As traders closed their books on September and dealt the first daily product for October, power prices drifted in mixed directions in the eastern two-thirds of the U.S. on Friday, Sept. 28. ... Across the U.S., demand remains a muted driver as the mild fall air keeps weather-related demand balanced between cooling and heating needs. However, a growing number of outages continued to lend power prices a push higher, especially with natural gas prices once again on the rise, meaning replacement generation is likely to cost more, too.” (SNL Energy’s Power Daily, 10/1/12)

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Average nuclear plant availability fell one percent last week, to 83 percent nationwide. Beaver Valley 2 began a planned refueling and maintenance outage September 24. Brunswick 1, Nine Mile Point 1, and Monticello returned to service after brief maintenance outages. (Platts)

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For more of the report click here.

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NEI Energy Markets Report (September 10-14, 2012)

Here's a snippet of what went on in the energy markets last week:

Electricity peak prices were mostly down last week. Prices at ERCOT-Houston, PJM West, and the Northeast hubs fell substantially, dropping $27, $20, and $11/MWh, respectively. Prices at Palo Verde and the Southwest hubs rose marginally, in the face of a heat wave. “Largely defying a typical pre-weekend tick higher, power prices for Sept. 17 delivery moved in both directions across the U.S. on Friday, Sept. 14, but with the bias mostly lower as traders focused on softer gas prices and mild fall weather rather than mounting outages or the return of business-related demand early in the next week. … The cost of gas could have heightened influence at the power markets in the coming weeks as large baseload reactors drop offline for routine seasonal maintenance. In total, almost 39,000 MW of supply is already offline nationwide, up about 4,000 MW on the day, according to data from IIR Energy. By fuel, there are more than 14,000 MW of coal-fired outages, more than 5,700 MW of gas-fired outages and almost 12,800 MW of nuclear outages” (SNL Energy’s Power
Daily – 9/17/12).

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Uranium spot prices fell to $47/lb U3O8 last week. “Demand is currently weak in the spot market, on the part of all groups – traders, financials, utilities, and producers. The relative lack of demand on the part of traders is somewhat derivative of the fact that demand is weak in the mid-term market, and hence traders do not have much motivation to delve into the spot market to buy and hold to meet mid-term needs. A non-U.S. utility recently entered the mid-term market, but beyond this, there is not much demand. Price is falling to a point where it may spur more interest on the part of utilities, but it still may have some way to go to stimulate any notable demand by this group” (Ux Consulting’s Ux Weekly – 9/17/12).

For more of the report click here.

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NEI Energy Markets Report (September 3-7, 2012)

Here's a snippet of what went on in the energy markets last week:

Electricity peak prices were mixed last week across the country. ERCOT-Houston and PJM West hubs saw the most action, rising $20 and $12 to average around $55/MWh, respectively. Prices at the Western, Northeastern and Southeastern hubs remained soft, moving less than $5/MWh in either direction. “Power prices across the United States moved mostly higher Tuesday, Sept. 4, with the largest gains recorded in parts of the East and Midwest after markets were closed Monday for Labor Day. … PJM West jumped more than $10 on the day with trades in the mid- to upper $50s, driven in part by a higher demand forecast as the PJM grid operator expects demand in the Western region reaching 69,700 MW on Wednesday. … As the Gulf Coast recovers from Hurricane Isaac's landfall last week, hotter weather and higher demand helped push ERCOT power prices higher Tuesday” (SNL Energy’s Power Daily – 9/5/12).

Average nuclear plant availability remained at 90 percent last week. After brief outages, Palisades, Three Mile Island 1, Turkey Point 3, Watts Bar 1, and Waterford 3 returned to service. Dresden 2 closed for five days to “perform maintenance work on water tubes in the unit's condenser.” Limerick 1 closed for four days for inspections, repair and testing of its low-pressure turbine blades. (Platts)

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For more of the report click here.

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NEI Energy Markets Report (August 27-31, 2012)

Here's a summary of what went on in the energy markets last week:

Electricity peak prices made marginal gains last week across the country. The largest movers were the Western hubs which increased $4-$6 to average $40/MWh in the region. The Eastern hubs barely budged and the Texas hub rose $4 to average $36/MWh. “Power prices across the U.S. moved in mixed directions Tuesday, Aug. 28, finding support from hot weather in California, across the Southwest and Texas but taking on a more bearish bias elsewhere across the country in line with weak spot gas prices. … In addition, generation remains healthy. While several units are slated to shut through September and October, a fairly minimal 22,790 MW is offline nationwide in the meantime, according to IIR Energy. The nuclear generation sector, which could see as many as 30 reactors shut for refueling by the end of the year, represents the largest market share of outages, with 8,337 MW offline. In addition, about 5,568 MW of the total is coal-fired and more than 4,000 MW is gas-fired, IIR said” (SNL Energy’s Power Daily – 8/29/12).

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Uranium spot prices fell to $48/lb U₃O₈ last week. “Although a significant portion of the lowest-priced supply has been cleared from the market, demand remains thin and highly price sensitive at month’s end. Some potential buyers have yet to enter the spot market in spite of the recent drop in the price. In the case of many utilities, there is little room or budget available for inventory or discretionary purchases, and those interested in taking advantage of the price drop must procure management approvals before proceeding. In addition, several market participants still expect that prices could fall even further and, therefore, are delaying purchases in hopes of securing material at even lower prices” (TradeTech’s Nuclear Market Review – 8/31/12).

For more of the report click here.

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Turkey: Nuclear-Natural Gas Quid Pro Quo?

No argument here:

One of the world’s fastest-growing economies, Turkey has significant energy needs. The majority Muslim nation’s energy demands will double by 2023, according to one projection.

Nuclear Energy perhaps? Turkey has contemplated it for some years, but lacked a partner to help cover the expense of building the facility- running nuclear energy plants is inexpensive, building one is expensive. Now it has a partner – and in an arrangement that seems close to unique:

The $20 billion venture will be wholly financed by a subsidiary of Rosatom, Russia’s state-controlled nuclear energy corporation.

The Russian firm has agreed to build, own and operate the plant for its entire productive life, with spent fuel sent to Russia for reprocessing. The deal represents an unprecedented level of cooperation between the former adversaries.

Various Turkish officials have a lot of questions about this, some of which involve national sovereignty, always a touchy subject. For example, Turkey doesn’t have a nuclear regulator at present and it’s uncertain whether the new plant will be regulated by the Russians or the Turks. Additionally, it isn’t clear which country will decommission the facility. To be honest, these items can be worked out in time – I suspect it is the Russian connection that gives them an air of urgency.

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Most interestingly, though, there is the strong implication that Russia isn’t doing this solely (if at all) out of the kindness of its heart:

Gas- and oil-producing giant Russia has enlisted Turkish support for its proposed South Stream pipeline to diversify its access points to European markets.

There’s no direct evidence of quid pro quo, though plenty of evidence of heavy negotiation that included both the nuclear facility and the natural gas line – almost every story I looked at yoke them together, which suggests, at the very least, that the two projects represent a single unit that will proceed in sync. In fact, Turkey and Russia signed 17 (mostly) energy-related agreements in one go, which in itself has aroused a good deal of concern in Turkey.

But most of that number [$100 billion in trade] comes from Turkish imports of Russian oil and gas, and some Turkish energy experts cautioned that the increase would do more good for Russia than for Turkey. The deal for the nuclear plant, scheduled to be built over seven years in the Mediterranean city of Mersin, raised further concerns among some Turks of relying too much on Russia.

This is from the NY Times and it too keeps the natural gas and nuclear projects closely linked. Still, even if there is more correlation than causation here, I wondered if there was more to the Turkish involvement in the natural gas line.

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Indeed, there is a kind of race going on between Russia and Europe to build a viable natural gas line to serve European markets, with Turkey involved in both of them.

The South Stream gas pipeline is intended to provide a direct connection between suppliers and consumers, thus avoiding transit risks and guaranteeing a continuous energy supply for Europe. Nabucco on the other hand, aims to bring Caspian gas supplies to Europe to reduce dependence on Russian gas imports taking a northern route from the Turkish-Bulgarian border to Austria.

The story doesn’t really explain what Nabucco is all about, but it does point out that diversifying the supply of natural gas is important – and it is. Let’s take that as a given.

Nabucco is a consortium formed by Turkey, Romania, Bulgaria, Hungary and Austria. The European Union supports it and so does the United States – because much of the natural gas will come from Iraq. The pipeline itself stretches from Turkey to Austria, with feeder lines from Georgia and Iraq.

The South Stream line, meanwhile, will carry Russian natural gas through Bulgaria and Turkey and on to Italy. This already tortuous route is necessitated by bypassing Ukraine, which wants no part of the project (Russia accused Ukraine in 2006 of stealing natural gas flowing though the latter, a conflict that got bitter quickly; in 2009, Russia rather roughly shut down the natural gas supply to the west for reasons not fully explained, stranding some countries, such as Bulgaria, in the middle of a harsh winter. See here for more on that). Losing the Ukrainian option meant involving Turkey, even if it provides a less than ideal route.

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Check out the Nabucco and South Stream web sites for a more complete accounting of the pipelines. Note, too, that I have no brief on natural gas pipelines and their doings. In the parlance of American politicians, no winners and losers here. (Both pipelines serve a practical purpose and both serve natural gas-poor Europe. If Nabucco backstops Russian petulance, consider it a bonus.)

In the end, what’s really worth discussing is a 1200 megawatt Russian nuclear facility at Mersin. It’s ultimately up to the Turks to decide if that’s a good idea and so far, and with some dissent, the decision is – yes. It works for Turkey.

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NEI Energy Markets Report (August 20-24, 2012)

Here's a summary of what went on in the energy markets last week:

Electricity peak prices fell $1-$16 last week across the country to all settle below $40/MWh. “Next-day power markets were mixed but generally lower across the U.S. to open the workweek Monday, Aug. 20, as traders eyeballed higher load forecasts in most areas but also weak natural gas prices and an overall healthier generation picture. … Other sources of generation were improving Monday. According to data from IIR Energy, just more than 19,300 MW of various generation was offline across the U.S. early Monday. By fuel type, 3,866 MW was coal-based, while about 8,150 MW was nuclear-based and 1,969 MW was natural gas-driven” (SNL Energy’s Power Daily – 8/21/12).

Electricity production was down 8.3 percent last week compared to the same week in 2011. For the first 34 weeks of 2012, electricity production is down 2.3 percent compared to the same period in 2011.

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For more of the report click here.

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By the Numbers: The Benefits of New Hampshire’s Seabrook Nuclear Station

Today, the Seabrook Public Library is showing a film that highlights the start of the anti-nuclear power community. The film is about a long-ago protest in 1977 in which activists opposed to nuclear energy tried to occupy the Seabrook plant site during construction. Seabrook finally got built, and in the 22 years since it began producing electricity, it has amassed an impressive record of economic and environmental benefits.

Reliable Electricity

According to the Energy Information Administration, the Seabrook nuclear power reactor (1,247 MW) is the largest in New England and provided 42 percent of New Hampshire's 2011 electricity generation. Since it began commercial operation in 1990, the unit has produced a total of 189,684,433,000 kilowatt-hours, or more than enough electricity to power New York or Illinois for a year.

According to NextEra, its owner, Seabrook generates enough power to supply the annual needs of 1.4 million families and businesses.

Environmental Benefits

If Seabrook wasn’t in operation, the electricity for those 1.4 million families and businesses would likely be generated from fossil fuel plants. In 2011, based on data from EIA and EPA, Seabrook’s clean nuclear electricity avoided the emission of 6,200 tons of sulfur dioxide, 1,400 tons of nitrogen oxide, and 4.0 million metric tons of carbon dioxide that would have otherwise come from fossil fuel plants.

That volume of carbon dioxide is equivalent to the CO2 emissions from 774,000 cars each year. For perspective, there are only 619,000 cars in New Hampshire.

If a coal plant had been built instead of Seabrook, it would have emitted nearly 190 million metric tons of CO2 over 22 years - more than the CO2 emissions from the entire state of New York in 2009. If a natural gas plant had been built instead of Seabrook, it would have emitted nearly 94 million metric tons of CO2 over 22 years - nearly equal to all of Arizona’s CO2 emissions for the whole of 2009. (For background, one metric ton of CO2 is emitted for every megawatt-hour (MWh) generated by a coal plant. Similarly, one-half of a metric ton of CO2 is emitted for every MWh generated by a gas plant.)

Natural Resources Saved

Besides avoiding emissions, operation of the Seabrook nuclear station also avoids massive quantities of coal, natural gas and land resources that would otherwise be consumed in replacing Seabrook’s electricity output.

The amount of coal saved since 1990 is about 95 million short tons, or nearly the amount of coal consumed in a year by Texas - the largest state consumer of coal.

Had Seabrook been a natural gas plant, 1.5 trillion cubic feet of gas would have been consumed since 1990 which is more gas consumed in a year than each of the three largest state consumers of gas: Louisiana, Florida and New York.

(Based on EIA figures, about half a short ton of coal is consumed to generate one MWh and about eight cubic feet of gas is consumed to generate one kWh.)

Besides the amount of coal and gas avoided by Seabrook, it’s useful to point out how much land would be required if the unit were replaced by wind turbines or solar panels. In order to produce the same amount of electricity in a year as Seabrook does, you need about 290 square miles of wind turbines or about 80 square miles of solar panels. The Seabrook station, on New Hampshire’s coast, covers 1.5 square miles.

(The source of the renewable land info is found here and the calculations above account for solar and wind’s low capacity factors.)

Although it doesn’t burn coal or gas, Seabrook does use nuclear fuel. Since it began operation 22 years ago, Seabrook has used 550 metric tons of nuclear fuel. This quantity is small enough to store on Seabrook’s site and even small enough to fit on a Best Buy parking lot, including the fuel assemblies and protective covers.

Economic and Community Benefits

According to NextEra’s website, Seabrook provides many economic benefits to its employees and the community. During normal operations, the station employs 1,100 people. During the refueling and maintenance outages that take place every 18 months, the number of employees doubles to 2,100.

Further, each year, the plant pays $100 million in employee salaries which then trickle down through the economy, and another $20 million in property taxes that goes to the local communities to pay for schools, roads and other public services.

Many More Years of Service

Seabrook is one of the younger nuclear stations in operation and has another 18 years before its current 40-year license expires. The unit has applied to the Nuclear Regulatory Commission to operate for 60 years and there is much discussion and research going on in the industry to determine how nuclear plants can operate for 80 years. Seabrook could be around for quite a few more generations -- helping to avoid emissions and save resources while providing substantial economic benefits and reliable electricity to its community, New Hampshire and New England. As the nuclear critics will celebrate their efforts, in reality, it’s a great thing for the community, and the country, that the station was actually completed and put into service.

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