Saturday, January 7, 2017

Ending the Fear of Nuclear Energy (video)

My friend Michael Shellenberger delivered a TEDxCalPoly talk: How Fear of Nuclear Ends.

This is a terrific talk, tracing opinions on nuclear energy from the days when the Sierra Club policy "Atoms not Dams, (because of the huge ecological impact of hydro plants).  Then he describes  the controversy and confrontation within the Sierra Club as subgroups pushed against nuclear power. The quotes from the early anti-nuclear people are very telling: these people are basically against clean power because it would lead to population growth or economic growth or both.

Shellenberger talks about how anti-nuclear fears were nurtured by a small group of people, and how anti-nuclear fears will end.  One reason they will end is because everyone wants---a better world for our children.


Wednesday, January 4, 2017

Pay for Performance on the U.S. Grid: No help to nuclear

Happy New Year to everyone, and especially to readers of this blog!  

 I plan some posts on nuclear power and grid policies.

This post shows how instituting  Pay for Performance does not help nuclear plants. The post is an expanded version of my article, Pay for Performance on the U.S. Grid, at Nuclear Engineering International, February 2016.   I am grateful to Nuclear Engineering International for permission to use their graphics.

No Help to Nuclear: Pay for Performance on the U.S. Grid

The United States electric system contains both traditional (vertically integrated) and “liberalized” markets.  In the “liberalized” markets, RTOs (Regional Transmission Organizations) and ISOs (Independent System Operators) operate the grid, using free-market auctions.  The RTO areas are the most challenging for the American nuclear fleet. All the nuclear power plants that are in danger of shutting for economic reasons are in RTO areas.
RTO Areas, from FERC

Neither RTOs nor vertical integration are perfect systems for pricing electricity. RTOs are relatively new (started in the 1990s) and are still evolving their policies.  In particular, some RTOs are planning to reward more-reliable plants by instituting “Pay for Performance,” starting in 2018.  Unfortunately, despite the hopeful name, this change is not likely to help nuclear plants.

The RTOs were designed to lower costs for consumers by giving them the benefit of free-market pricing: electricity is bought in an auction. When the ISO needs power, plants “bid in.” ISO chooses the lowest price power first, moving up the bids until all the power needs are met.   Power plants and utilities can also negotiate Power Purchase Agreements (PPAs) at mutually agreeable prices, and a great deal of electricity is sold in this manner. However, in many markets, investor-owned utilities are prohibited from entering into long term PPAs with conventional generation sources. At any event, PPA electricity prices tend to follow grid pricing, though sometimes with a major lag time.


The Missing Money

Actually, there are two auctions: the energy auction (electricity) and the capacity auction (power plant availability).  (See Sidebar below.)

Search for the Missing Money
James Bride, Energy Tariff Experts
Unfortunately for the energy auction theory, the real-time energy auction plan immediately ran into the first “missing money” problem.  Why should owners of higher-priced plants maintain their plants? Their plants are not guaranteed a price (while on the grid) nor are they guaranteed a number of hours that the grid is sure to call on them, and for which they will be paid.

It became clear that paying only for energy (kWh) might not provide enough money to maintain all the plants that are needed for reliable grid operation.

At a recent meeting of the Consumer Liaison Group for ISO-NE, James Bride of Energy Tariff Experts provided excellent graphics on this subject. (See slides 9 and 10 of presentation below, one of which is included above.)
http://www.iso-ne.com/static-assets/documents/2015/10/clg_james_bride_keynote_presentation_10_9_2015.pdf

The Second Auction and the Capacity Payments

To pay plants to be available, plants now bid into a second auction, an availability auction called the Forward Capacity Auction.    As you can see in the following chart (prepared from ISO-NE data by Entergy, and used with their permission), the Capacity Auction made it possible for gas turbines and peaking plants to make up enough money to keep operating.  The capacity auction found the missing money for some of the plants.

As you can also see, nuclear plants get most of their money from energy payments, not capacity payments.  That is because nuclear plants make so many kWh, compared to other types of plants with the same nameplate capacity rating.  Ultimately, of course, the grid is all about kWh delivered.

(See the sidebar below for sample calculations.)
Revenue streams for different types of plants
Courtesy Entergy and Nuclear Engineering International

Problems with Capacity Auctions

Capacity auctions did not completely solve the reliability problem. They find some missing money, for some types of plants. But what happens when the plant receives the capacity money, but then---later---when called upon to run by ISO, the plant doesn’t run?

ISO-NE and other ISOs were aware of this potential problem, and began designing Pay for Performance incentives. These incentives were to start in 2018.  However, meanwhile, the shale gas boom happened, and the grid became more and more dependent on natural gas. The ISOs needed something for winter reliability, something they could put in place more rapidly then Pay for Performance.

Capacity Auctions Mislead the Grid

Prices during a Polar Vortex
In many ways, the capacity auction results misled ISO about the amount of electricity that would be available to the grid in crisis situations.  During cold snaps, much less electricity was available than had been bid into the capacity auction. Natural gas power plants rarely have firm gas transportation contracts with pipelines.

The gas plants made firm capacity commitments to the grid but did not  have firm delivery commitments for natural gas supply. The Polar Vortex laid bare this problem.

In winter, the ISOs needed a quicker winter fix than Pay For Performance, so they started “winter reliability programs.”  These programs were started just in time. During cold snaps, gas plants not coming on-line was driving the grid closer to the situation where it would have to “shed load” in a cold snap.

The Winter Reliability programs were complex, including new types of auctions.  Basically, however, they supported plants to keep oil, CNG and LNG onsite to burn when gas was not available.  ISO paid for oil, or paid storage costs for unburned oil. FERC (the Federal Energy Regulatory Commission) approved the Winter Reliability programs on a temporary basis. But FERC disapproved of the fact that the reliability programs were not fuel-neutral, and ISOs are supposed to be fuel-neutral.  Therefore, FERC and ISO look forward to 2018, and PFP.

Pay for Performance

Pay for Performance (PFP), which will start in 2018, is supposed to be fuel-neutral. PFP is supposed to find yet another kind of “missing money.”  It is supposed to provide the economic incentive that would encourage power plants to come on-line when dispatched during tight situations on the grid.

Sadly, PFP isn’t actually market-based.  It is a complex regulatory system, basically jury-rigged, that satisfies FERC requirements by supposedly being fuel-neutral.

 PFP is a transfer mechanism from poor-performing plants to high-performing plants.  If a plant bids in capacity, but then does not provide energy (electricity) when called upon, it will have to forgo part (or maybe all) of its capacity payment for that month.  The loss of this money is a sort of penalty for the plant. This lost-money will be added to the capacity payments of plants that do perform during a high-load period, as a sort of bonus.

With PFP, a plant might well lose its entire capacity payment for a month if it doesn’t go on-line when it is needed. It might even owe ISO-NE money beyond its capacity payment. This would be quite a blow for a plant that depends on capacity payments, such as a natural gas plant. An ISO-NE hypothetical example shows a 100 MW plant losing or gaining $50,000, $150,000, and $350,000 dollars in a month, under various scenarios.  http://www.iso-ne.com/committees/comm_wkgrps/strategic_planning_discussion/materials/fcm_performance_white_paper.pdf

Nuclear plants may get some extra payments from PFP, but these payments would be part of their capacity payments.  For nuclear plants, capacity payments are a small portion of their revenue stream, and PFP will not make much of a difference to their pay stream.

The major effect that PFP seems to have had is to encourage all new gas-fired plants to be dual-fired, so they can keep oil on-site and keep their capacity payments.

As ISO-NE in their statement about Pilgrim closing: “Most of this new gas-fired generation is seeking to become dual-fuel capable, meaning they will be able to switch to use oil if natural gas is not available, or if the cost of oil is lower than that of natural gas.”
 http://www.iso-ne.com/static-assets/documents/2015/10/20151013_pilgrim_retirement_request.pdf


PFP Problems for Steam Plants

Steam turbine
With PFP, there’s a lot of devil in the details.  One issue is that it does not distinguish between various types of plants, and could penalize plants that raise steam.  PFP depends upon a complex formula which is the result of many debates on how to structure incentives for plants to be online.  The amount of the penalty/transfer payment depends on this formula, and the formula partly depends on the situation on the grid.

There is considerable concern that some of the PFP transfers will be random--power plants will be penalized or rewarded for situations they can do very little about. A representative from NEPOOL had harsh testimony against PFP. (NEPOOL is a voluntary association of New England energy market participants. It was founded about twenty years before ISO-NE.)  http://www.nepool.com

To quote Elin S. Katz, office of Consumer Counsel in Connecticut, testifying behalf of NEPOOL:  http://elibrary.ferc.gov/idmws/file_list.asp?document_id=14178339  (Katz testimony, available only by download.)
PI (PFP) creates excessive investment risk because.... PI’s substantial penalties would impact capacity suppliers that are not operating during particular five- minute intervals regardless of the reason why they were not operating. PI would ignore the actual operating characteristics of a power plant when levying penalties. 

Katz gives an example in which a steam power plant bids into the day-ahead market, is not selected for that market, but then it turns out that ISO-NE does need its power.  Steam plants cannot come on-line very quickly, and ISO-NE PFP assesses penalties on a five-minute basis. The problem in this case is actually the result of ISO’s imperfect prediction capabilities, but the fines will be paid by the steam power plant.

 PFP and Burning Oil

Well, PFP is messy, and PFP may be unfair.  Let’s ask another important question, though. Will PFP help nuclear power?  Will PFP finally reward nuclear plants for their reliability?

The answer is No.  PFP will not help nuclear plants. The main result of PFP has been for natural gas plants to commission or recommission dual fuel capabilities so that they can burn oil.

Nuclear plants get most of their revenue from energy payments, not capacity payments.  Nuclear plants may get some higher capacity payments through pay-for-performance, but this will not make a big difference to them. The pay-for-performance transfer will make a difference to the peaker plants, which will have more of an incentive (however oddly arranged) to become dual-fuel or make other arrangements to be able to come on line when called.

Are RTOs really a market?

The whole RTO situation is getting pretty far from “a market,” as markets are usually considered.  Nuclear power plants in RTO areas of the United States are not well valued for their steady performance and PFP will not change that.  Meanwhile, the RTO market-solution is becoming an increasing series of tweaks and attempts to keep the grid operating smoothly. The tweaking in RTO areas (including PFP) is interesting and complex, and it becomes more complex all the time.

Complex markets become complex as they are regulated to achieve certain goals.  In general, RTO markets favor plants with low capital costs, high fuel costs and low utilization compared to plants with high capital costs, low fuel costs, and high utilization.  This is the outcome of the current market design.

 In other words, RTO markets are unfavorable to nuclear power. Whether this outcome was a goal of the design (a feature) or an unintended consequence (a bug) is not clear.  At any rate, despite all the tweaks, RTO markets allow local grids to move to heavily to natural gas, despite problems with gas delivery. Except for dual-fueled plants, Pay for Performance will make little difference.

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RTO auction sidebar: Doing the math for capacity payments

RTOs generally run two types of auctions: a real-time energy auction, and a Forward Capacity Market auction.  Both auctions work basically the same way: Plants bid in to supply either kWh right now (energy auction) or capacity availability some years in the future (Forward Capacity Auction). The auction requirements fill from the bottom--the least-cost plants are selected first.  In both auctions, plants usually bid the lowest price they can bid, to be sure they are chosen.  The RTO has to fill its needs, however, so it cannot just choose a few low-price plants.  At some point, with higher-priced plants, the RTO requirements are filled. In both auctions, all the bidders get the payment for the highest price plant that is accepted into the queue.  The auctions are meant to move prices in synch with demand, and always provide the lowest price that meets the demand.

Where do different plants get their revenue under this system?

Let’s look at an overly simplified example:

Let us assume that we have a price on the grid of 4 cents per kWh, and a capacity price of $3 per kWmonth. (This is a very rough approximation to the situation on the New England grid recently.)

We imagine a 500 MW nuclear plant and a 500 MW combined cycle gas plant.

  • They will both get the same capacity payment of $1,500,000 per month, because they have the same capacity.  
  • The nuclear plant has a 90% capacity factor, and earns approximately $13 million for energy payments. 
  • The combined cycle gas plant capacity factor is about half of that of the nuclear plant (around 40-50% capacity factor, according to EAI, I am assuming 45%), so it makes half the electricity as the nuclear plant. It earns approximately $6 million in energy payments. 

In this highly simplistic case, the capacity payment for the nuclear plant is about 10% of its revenue stream, but it is 20% of the revenue stream for the gas plant.  If the gas plant were a “peaker,” running about 10% of the time, it would receive the same capacity payment as the other two plants. However, it would earn only $1.5 million in energy payments. For a "peaker" plant,  capacity payments could be about half of its revenue.

One way in which this analysis is overly simplistic is that the gas-fired plants are likely to only be on the grid when the grid prices are running higher than average.  Nevertheless, this gives a high-level overview of capacity and energy payments for various types of plants on the grid.

For a nuclear plant, even a small decrease in energy prices can override a modest increase in capacity payments. This is the main reason why PFP will not affect nuclear economics very much.









Friday, December 30, 2016

Hello Governor Scott, and Goodbye Shumlin!

Governor Shumlin's Christmas Greetings

Governor Shumlin (soon to be ex-Governor Shumlin) has been a fierce and unremitting foe of Vermont Yankee.

Yeah, yeah, we know that.  But I was still surprised to see a story by Mike Faher breaking on Christmas Day this year. Here's the article in VTDigger December 26,  Shumlin: Vermont Better Off Without Nuclear Plant.  Two years after the plant closed, and Shumlin is still crowing about closing it?  This is what Shumlin wants to say, just before he exits from being Governor?

 From the article above, some quotes from Shumlin.
Windham County has an advantage for economic development because "We can do cash." (Cash from the Entergy settlement fund for economic development of Windham County.) 
Furthermore, Vermont is "an example of how to reduce your carbon footprint and do electric generation right." 
Here's my opinion of the real meaning of his statements:
  • First, Shumlin is  the "we" in the first statement. Entergy's $10 million in cash for Windham Country redevelopment will not make up for the loss of Vermont Yankee's payroll of 600 people.  However, Vermont Yankee controlled its payroll, while the Governor of Vermont (Shumlin) makes the final decision on how the Entergy economic development funds will be spent.   Indeed, Shumlin has controlled more cash after Vermont Yankee closed than he controlled when it was operating.  Shumlin could "do cash." That was his version of "we."  
  • Second, Vermont Yankee made 70% of the power made in Vermont.  Now, we import this power from the grid....adding some solar and some wind turbines in-state haven't exactly given us this power back. For Shumlin, "doing electric generation right" means that someone else generates the electricity, and they generate it somewhere else.
A Sad Anniversary

Yesterday was the second anniversary of the day that the plant went off-line forever,  December 29 2014.  My Facebook news feed includes many people sharing unhappy memories of the day. I did not enjoy reading Shumlin's cheerful words on Christmas Day as the anniversary approached.

I also encourage people to read my blog post about the consequences of the closing: Circles of Pain around Vermont Yankee Closing. 

Photo from the Phil Scott gubernatorial transition website
Goodbye to the Old Year

Some of my friends send me New Year Cards with the old Jewish saying:
Goodbye to the old year with all its curses: hello to the New Year with all its blessings.

A major blessing of the New Year is that Vermont's new Governor will be Governor Phil Scott.  I first heard of Phil Scott in 2010.  When Shumlin led the charge against Vermont Yankee in the Vermont Senate in 2010, then-Senator Scott was one of the four senators that voted to support the plant.  Twenty-six senators voted against, four voted for the plant.  Scott's vote was a profile in courage.  He urged the Senate to gather more information, and not just blindly charge to close the plant.

Here's the video of his remarks.



 
Governor Scott and A Party

And now, Scott will be Governor of Vermont!  Assuming the roads are clear, my husband and I are going to Governor Scott's inaugural ball next weekend. I don't  go to balls  and galas on a regular basis. However, until yesterday's deadline, anyone could buy a ticket.

In fairness to soon-to-be ex-Governor Shumlin, you could also buy a ticket to Shumlin's inaugural ball at the Sugarbush Ski Resort. Mary Powell, CEO of Green Mountain Power, was a major fundraiser for that ball.  I believe the ball was rather lavish.  Here's an older article that I wrote about the close ties between Shumlin and Green Mountain Power.  And here's an article in which Shay Totten wonders if it was just coincidence that Mary Powell raised $190,000 for the Governor's ball just before a Vermont agency needed to rule about a proposed Green Mountain Power wind farm. (Again in fairness, Shumlin's ball was a fundraiser for Vermont National Guard Charitable Foundation.)

Governor Scott's ball will be at a more modest venue: the Army Aviation Facility at the Burlington Airport.  Scott's ball will be a fundraiser for charities that support those who serve or have served in the military.  I plan to be there.

Vermont is not "better off without Vermont Yankee."  But Vermont will be better off without Peter Shumlin as Governor.  Hello, Governor Scott!




Tuesday, December 20, 2016

Celebrating and Advocacy

Collage of the Chicago Victory
Courtesy of Generation Atomic

The nuclear advocacy blog

I have a new post at my meredithangwin.com website blog.  I call that blog the Nuclear Advocacy blog, because my posts are all about advocacy, rather than general news.

My latest post is Joy and Celebration: Part of the Activist Toolkit.  Advocates saved the Illinois nuclear plants. Time to celebrate!

Celebration

In many circumstances, celebrating a win might  be just, "Of course we celebrate. That just goes without saying." However, I think that nuclear advocates sometimes skip that step.  We tend to look at the work-that-lies-ahead, which is admirable.  But it is also admirable to celebrate, because it is helps us stay motivated.  "YES!  We DID this!"   That's a good feeling, and makes us want to go out and do this again!

My husband used to be a member of the Western Wheelers bicycling club, and he often rode the Sequoia Century (and part-Centuries with the kids, when the kids were younger).  He told me when that when he was bicycling up a hill, he never looked up at the top of the hill.  It always felt discouraging to look at the top.  He said: "I just keep pedaling." Good advice for everyone.

And when you get to the top, celebrate!

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And please visit my new blog if you can!  I have a few posts up there already....
 




Wednesday, December 7, 2016

Wind Power in Vermont, After the Election: Guy Page Guest Post

Since Election Day,  the future of Vermont wind power is less certain

 Guest post by Guy Page


Election Day, November 8, 2016, was bleak for the future of ridgeline wind power in Vermont. The outcome of local, state and national voting signaled a vote of no confidence in the growth of utility-scale wind power in the Green Mountain State.

Local voting
Iberdrola, developers of the 24 turbine Styles Brook project, promised host towns Grafton and Windham there would be no development without voter approval by referendum. On November 8, Grafton voted 235-158 and Windham 180-101 against construction, and Iberdrola has said it will honor its commitment.

Local Vetoes a Harbinger
The Windham-Grafton vote was the latest in a line of anti-wind development referenda. Unimpressed by the 2016 Vermont Legislature’s conditional gift of slightly more say in the energy siting process, municipalities are now bypassing Montpelier. If this trend of “permission by referendum” continues, towns will have carved out a local veto power for themselves over ridgeline wind development. A new precedent is being set. This is Vermont, after all. One way or another, local people will jealously protect their control of the landscape.

State Results
During the governor’s race, candidate Phil Scott promised a moratorium on ridgeline wind development if elected governor. His opponent, Sue Minter, did not. Voters chose Scott by a nine-point margin. Minter even lost hometown Waterbury, where just 34 percent of residents (Waterbury Town Plan, page 65) support local development of utility-scale wind power. Of course, many others issues stirred voters, but the impact of the unpopularity of ridgeline development cannot be denied.

Statewide Policy
Gov. Scott is expected to keep his promise of a moratorium. He will almost certainly appoint a like-minded commissioner to lead the Department of Public Service, the state’s energy regulator. Most importantly, the term of Vermont Public Service Board Chairman James Volz expires in March 2017. Under his watch, ridgeline wind projects in Lowell, Georgia and Sheffield were approved and constructed. Governor-elect Scott’s choice to chair the PSB is anyone’s guess, but the logical choice would be a fellow ridgeline wind skeptic.

Presidential Election
President-elect Donald Trump has said wind power kills too many eagles and is an inefficient energy source, according to many media outlets. Trump also publicly called global warming a hoax and said he would restore the U.S. coal industry. In December 2015, he lost a lengthy battle to stop a wind turbine project offshore from his Scotland golf course.

National Outlook
The wind industry can be thankful that Congress extended the 2.3 cent/kilowatt-hour Production Tax Credit in 2015, even though it drops 20% every year and expires in 2019. In an impromptu interview with VTEP in Montpelier on November 22, U.S. Congressman Peter Welch said the Republicans who now control both houses of Congress “hate renewables” and that Trump supports fossil fuels. Wind power backers should not expect any new help from Congress or the new administration, he said.

This is especially likely to be true if Trump’s next Secretary of the Energy is his energy advisor, Oklahoma billionaire Harold Hamm. According to a November 19 Forbes article citing him as a leading DOE Secretary candidate, Hamm is the son of a poor sharecropper who built a trucking empire and then earned another fortune by hydrofracking oil and natural gas. Far from supporting wind subsidies, Hamm says wind should be taxed similarly to oil and gas – two percent on production in the first three years, and seven percent thereafter.

None of these local, state and national developments mean ridgeline wind has no future in Vermont. What government giveth, it taketh away, and may someday giveth back again. Thus, the next two state and federal election cycles may have different results. Still, one must wonder about the long-term sustainability of an industry that must rely not only on the ever-changing winds of nature, but also on the fickle winds of electoral politics.

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Guy Page with Great Grandfather
Urban Woodbury
Vermont Governor and
Civil War "empty sleeve"
Guy Page, a Berlin resident, is the Communications Director of the Vermont Energy Partnership, a coalition of Vermont individuals, trade, development and labor organizations, and businesses committed to clean, safe, affordable, reliable power in Vermont.  He is a frequent guest blogger at this blog.  His most recent post described how the Vermont Yankee decommissioning fund is supporting local schools.


Thursday, December 1, 2016

Nuclear vs Gas Economics Part 2: Guest post by Nick Escu

Nuclear Power vs. Natural Gas Power 3 Year Projection (Part 2)
By Nick Escu
LNG unloading arm in Japan

Part 1  of this post basically explained a few facts from historical data:
  • Nuclear plants today are not as economical as natural gas generation plants are today.
  • Natural gas prices have consistently had ups and downs. When natural gas prices are high, nuclear plants become very profitable. When natural gas prices are very low, nuclear plants become unprofitable.
Changing times and LNG

There are new kids on the block. Seventeen  new liquid natural gas export permits granted, and an additional  29 LNG permits partially approved (Energy.Gov-August17, 2016). This has changed the dynamic of the amount and pricing of natural gas leaving the US. There's a huge difference between U.S. prices and worldwide prices.

There is now a very positive indication that natural gas prices are rising, as in the case of the Henry Hub price for MMBtu in February, 2016 moved from $1.71/MMBtu to $2.98/MMBtu in October, 2016. A 75% increase in 8 months.

Will changes like this continue? Will there continue to be a such price changes?

EIA stats (November 14th, 2016) for November and December (Drilling Productivity Report) clearly show an increase production rate of 4% to 5%.

Why is this increase important?

Because as more of those 17 approved permits begin liquefying natural gas and exporting natural gas, the natural gas prices will continue to climb. More LNG (Liquid Natural Gas) produced and sold will increase the base US price for nat gas.

Natural gas producers will want to maintain their huge markups in the world. The world prices for nat gas, begin at the $17.50/MMBtu. Our prices here in the US are at $3.00/MMBtu, or an almost 600% markup value for natural gas. Huge profits from exporting gas from in the US.

LNG export abilities set to grow

A portion of the first LNG permit, licensed to Cheniere in Louisiana, has come on line, February, 2016.
Cheniere, in Louisiana, will produce 2.1 Bcf/day of LNG. But the total for all 17 approved permits, and the 29 partially approved permits will equal 53.8 Bcf/day of LNG for the world.

So now we clearly see why production of new wells and output has increased for the following 2 reasons.
  • First, the need to maintain the profit margin between US nat gas production and world nat gas demand. 
  • Second,  to have sufficient stock available for all 46 LNG exporters.

Nuclear power becomes profitable at about $4.75/MMBtu spot nat gas.

So Cheniere was the first test, with just their first unit out of 6 units.  Their first unit caused a gas price increase of 75% increase in 8 months. Now the market has balanced. But it will not be balanced for long!

The LNG exporters will need over 25 times the amount of nat gas and what we will see are nat gas prices following each new LNG exporter when they come online.

By the end of 2016, Cheniere’s Sabine Pass Trains 1 & 2 will be in operation.  In 2017, another three trains will probably start, some from Cheniere and others from Dominion’s Cove Point. By the end of 2018, five more new trains* may come online from Cameron, Freeport and Corpus Christi. Another four trains are due online in 2019 from Freeport, Corpus Christi and Sabine Pass. US LNG exports have only just begun.

We will see the nat gas prices rising in 2017. By the end of 2017, that $4.75/MMBtu price will be reached and every nuclear plant will again be competitive.

Think about the zero pollution from nuclear power plants versus all the pollution that the new natural gas power plants the world will produce.

Enough for now.

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Nick Escu is the pen name of a person with long experience in the power industry.

* A natural gas liquefaction facility consists of separate units, called "trains," each of which is set up to purify and condense natural gas.  So a facility can have one train or several.  Cheniere will have six trains.

Tuesday, November 29, 2016

Nuclear vs. Gas Economics, a Three Year Projection. Guest post by Nick Escu

Nuclear Power vs. Natural Gas Power 
A Three Year Projection
By Nick Escu


The power industry continually looks for a stabilized grid demand to operate profitably, economically and reliably.

There are several key factors the power industry looks at to determine these needs are met.

Profitability is determined by how much generation costs, plus outstanding production and grid costs are entailed. Factors affecting generation are fuel costs, labor costs, parts costs, plus new regulations, plus changes in overall demand.

Costs

We’re going to look at current nuclear power costs and three-year projected nuclear power costs, as well as current natural gas power costs and three-year projected natural gas costs.

We are not going to look at the huge increase in air pollution and power production costs caused by natural gas versus nuclear. These facts are readily seen in Germany which eliminated nine of its nuclear plants in favor of natural gas and a little wind and solar.  It has shown a 25% increase in power costs. Similarly,  Japan has at present, shut down all of its nuclear plants, with a huge increase of air pollution and power costs. Similarly in California which shut down two nuclear plants with subsequent air pollution increases and rising power costs. Enough has been written  about these examples, and will continue to be written in the future.

Let’s begin our analysis.

Selling price

We will first look at basic selling price of nuclear power per megawatt hour versus natural gas power per megawatt hour.

The EIA actual selling prices as of January 2013 for Mid-Atlantic generators were $32.00/ megawatt hour, and for the Midwest were $25.00/ megawatt hour.

Nuclear power plants are base load plants. They operate at 100% of their capacity for over 90% of their operating time. So when a nuclear plant is contracted to produce power to maintain the electricity grid in their region, they must operate. For most nuclear plants, the breakeven costs for power production are between $32.00 and $35.00 per megawatt hour. Anything less and that plant is losing money. And most businesses, unlike the federal government, do not operate on a loss revenue basis. They are in business to make money.

Natural gas

Now let’s look at natural gas power production costs.

In February of 2003, according EnergyOnline  the electric production costs were $990 per megawatt hour in Texas and New York City costs were $175 per megawatt hour.

But because of the tremendous fracking, current natural gas electric power production costs have dropped to $28.50 per megawatt hour in November, 2013, according to 4 Traders.

So we can see that if you have a nuclear plant that runs very economically producing power at $32.00 per megawatt hour and you also have a natural plant that generates power at $28.50, the logical choice would be to turn off the nuclear plant and make $3.50 for every megawatt hour.

Let’s put it in simpler terms. A 1000 megawatt power plant should run 8760 hours per year (the total hours in a year 365 X 24 =8760). Normal maintenance is about 10% of that time, so let’s subtract 876 hours for a net total of 7884 operating hours. Now let’s multiply that $3.50 more money the gas plant makes over the nuclear plant, times those hours, and those megawatts.

$3.50 X 7884 X 1000 =$27,594,000. This is the yearly gross profit a natural gas plant has over the nuclear plant.

If that was all we had to determine profitability and future projection, it would be a No Brainer. We’d shut down the nukes today, as long as we had plenty of natural gas plants.

But there another factor we must consider for the bottom line.  Short term versus long term.

Short term and long term

I’m an electrical contractor working in the power industry. A few years ago someone came to me and offered me $100 per hour to work, and the work involved 80 hours per week. Since I was between contracts, I took the assignment for a 2 month period of time, and made a nice chunk of change.

Shortly thereafter I took a 2 year assignment at $65 per hour, for a 60 hour work week. In the middle of that assignment the contracting group I’d previously worked at attempted to get me to go on an assignment to the same place, for a 3 week assignment. If I had known they were going to call me back, I could have let the new group know I’d be away for 3 weeks.

My decision was simple. I stayed with the 2 year assignment. Why? Because for the long haul, it was more profitable.

Sometimes short term profits cloud our judgment over the long haul.

Fuel cost trends

Back to natural gas.  I began this section by stating that in 2003 natural gas production costs were between $175 to $990 per megawatt hour.

So now let’s look at the consistent biggest cost to nuclear plants, the cost of nuclear fuel.

In 2003 nuclear fuel costs averaged $57,000,000 for a 2 year fuel cycle for a 1000 megawatt power plant. 2013 average cost for the same fuel is $60,000,000, or a 5% increase over the past 10 years or an average of 0.5% per year increase for nuclear fuel.

Natural gas prices decreased from $990 to $28.50 or a 97.2% decrease in power production cost.

But is that price of $28.50 per megawatt stable or is it changing?

The World and Us

Let’s look at the world prices. The prices vary from $57.00 per megawatt hour in Europe to $116.00 per megawatt hour in Asia. Why? Because of fracking here in the US, our prices are so low. That guy on TV says “We have enough natural gas for 100 years” remember him?

But a new factor has risen, LNG exporters. The President has signed 17 permits to now export liquid natural gas to all those places willing to pay a little less than what they have now. So what will that do to our US prices of natural gas??? Do you really believe our gas prices will decrease?

No, all of you are realistic. Our prices will increase.

A good example is that gasoline in the Emirates was a few years ago $0.25 per gallon, but today it’s about $0.70 per gallon. Why? Exporting your home product raises your costs locally. In the Emirate’s case, almost 300% increase.

Let’s be conservative and say our natural gas prices will only double here in the US after we start exporting. How long will that be?

The LNG export sites are even as we speak, running new power lines for the 11,000 and 12,000 horsepower compressors that turn the gas into a liquid. Estimates at present are 3 years (or 2020) for the last permit construction completion and production beginning and exporting.

Cheniere began production and first export happened in mid-February, 2016. Natural gas price in late February, 2016, was $1.71/MMbtu (Henry Hub). As of the end of September, 2016, the price for nat gas had risen to $2.99/MMbtu, a 75% increase in less than 9 month.

So do we really want to completely shut down a minimum producer like a nuclear plant today, when in 2 years it will be worth twice its value?  It’s a penny wise pound foolish decision.

Nuclear and Us

The optimum plan would be, pay for, build and use the gas generation now, and temporarily place the minimal nuclear plants in a hold status, much like had been down at Brown’s Ferry and Bellefonte. The stability we’ve seen with nuclear power far outmatches in price fluctuations what we’ve seen in natural gas.

Let’s see how a closed nuclear plant power production has been supplied.

Vermont Yankee closed December, 2014. VY was a 620 MWe plant supplying most of the electricity generated in Vermont (72%). Gets a little tricky here. So what replaced the nuclear baseload power?

Right, natural gas.  The rise of gas on the grid almost exactly replaced the fall of nuclear on the grid.  Green Mountain Power distributes most of the power in Vermont, and they are wholly owned by Gaz Metro of Quebec.  Gaz also distributes nat gas through Vermont Gas Systems.  This is a company that is always happy to see more gas on the grid, and more energy imports from Canada.

Additionally, the Vermont government and Green Mountain continue to purchase power produced by YES, You Guessed It, Seabrook Nuclear Plant.

Now most all of Vermont is dependent on nat gas. And everyone is begging for larger natural gas pipelines, because no nat gas, NO POWER! Great move ecologically minded Vermont. 200,000 Vermont homes using electricity from natural gas instead of nuclear produce the following: 38,000 tons of NOx, 78,000 tons of SO2, 96,000 tons of CO2, and 104,000 tons of particulates. But all those numbers were at or near ZERO tons with Vermont Yankee Nuclear plant????

How about Connecticut? What’s their gas situation like? Legislators were just denied new nat gas lines, because under FERC guidelines, all required consumption must be contracted prior to build out of pipelines. Sorry Connecticut. No contracts, no new nat gas pipelines.

To be continued

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Nick Escu is the pen name of a person with long experience in the power industry.