Sunday, January 31, 2010

US unemployment animation shows relative strength in NH

I stumbled on this neat animation that visualizes changes in unemployment rates across the country during the recession (hat tip: Coordination Problem blog).

As the animation completed, I was struck by how New Hampshire was pretty much alone in the northeast as a lone bright spot (mostly bright red, indicating a 5-6% rate) in a sea of dark red and purple across much of the rest of the country.

Unfortunately, new data released last week show the overall NH rate has increased to 7.0%. That's still well below the US average unemployment rate of 10%, but it moves most of the state from bright red to dark red or even purple in the animation.

One other thing from the animation that struck me was how well the midwestern farm states seem to be faring in this downturn. That shouldn't be surprising, since demand for agricultural products usually holds up better than demand for durable goods in a recession. Still, seeing all that bright yellow spread across the farm-belt really drove it home for me.

I did a bit of googling in search of a midwestern viewpoint (rather than a granite one) and I stumbled on this article by Sharon Schmickle at It provides some local color on the employment and economic situation in the farm-belt region.

As an aside, has an interesting new-media business model. They're a non-profit web-only publication staffed by professional journalists doing feet-on-the-ground reporting:

Monday, January 25, 2010

Electricity in NH - Did Massachusetts voters just save PSNH ratepayers some money?

Construction of scrubber at Merrimack Station in Bow, NH (summer 2009)

Occasionally, events and circumstances interconnect in unexpected and intriguing ways. The election of Scott Brown to the US Senate by Massachusetts' voters could give us another example of this and may have a surprising impact for New Hampshire.

The economics of PSNH's scrubber project were looking a bit tenuous in light of increased costs, lower natural gas prices, and looming carbon pricing legislation. Last week's election may end up changing all that. In fact, it may even make the cost of electricity from a "scrubbed" Merrimack Station relatively inexpensive for PSNH ratepayers.

First, there was this from Bloomberg last week:

“A large cap-and-trade bill isn’t going to go ahead at this time,” Senator Dianne Feinstein, a California Democrat, told reporters in Washington yesterday.

The cap-and-trade bill may not be completely dead, but most pundits believe it's at least mostly dead. This follows the Republican takeover of a seat formerly held by Democratic Senator Ted Kennedy in Massachusetts.

Impact on the environment notwithstanding, the death of cap-and-trade legislation could save PSNH ratepayers a hefty sum. Carbon emissions were estimated to cost $20-30 per ton and Merrimack Station alone emits over 3.5 million tons of carbon each year.

As a sort of plan B, in case the cap-and-trade bill failed, the EPA has been threatening to regulate carbon emissions itself under its Clean Air Act authority. The EPA recently classified CO2 as a dangerous pollutant and appeared poised to enact new regulations on emissions.

With last week's election, congress may now block the EPA's move to regulate CO2. At a minimum, the election results will make it tougher for the EPA to claim new regulatory authority. That means "plan C" may be called into action. Under plan C, the EPA would tighten regulations on other pollutants that coal-fired power plants emit, namely sulphur dioxide and mercury. The idea is that tighter regulations would increase the cost of making electricity with coal, and thus reduce the use of coal as a fuel for making electricity. This would be easier to do politically than enacting new legislation or claiming brand new regulatory authority over CO2, and would likely still result in a large decrease in CO2 emissions as a side effect.

Here's a quote from Kate Mackenzie at the Financial Times' FT Energy Source blog:

Like many others, Bernstein Research analyst Hugh Wynne thinks the election of Scott Brown to a Massachusetts Senate seat last week is a death knell for cap-and-trade legislation, at least under this administration (we don’t necessarily agree with this assessment, but more about that later). And like others, he points to new EPA regulations as being an alternative source of curbing greenhouse gas emissions.

Only instead of the EPA’s CO2 endangerment finding, it’s the proposed tightening of sulphur dioxide emissions rules that Wynne says could affect US coal-fired power plants so much that US demand for coal goes into ’secular decline’.

And there's the real twist. Merrimack's new scrubber is expected to limit emissions of both sulphur dioxide and mercury to amounts that are well below any future EPA limits. The plant will still be spewing out plenty of nasty CO2, but it should have no trouble complying with even the most stringent EPA regulations on sulphur dioxide or mercury.

So if SO2 and mercury regulations are the path the EPA takes to reduce coal-fired power plant emissions of CO2, that could set up a second windfall for PSNH ratepayers. As non-scrubbed coal plants begin limiting output or shutting down, coal demand around the country would likely decrease. That could result in reduced coal-prices and thus a lower cost of electricity for coal-fired (and scrubbed) power plants like Merrimack Station.

I know there are a ton of 'ifs' in the scenario described above, but it doesn't seem that far-fetched from a political standpoint. Personally, I think some sort of carbon pricing scheme would be a good thing overall. But if climate legislation does fail, I suppose it wouldn't hurt for PSNH ratepayers to get a little windfall. As usual, when it comes to electricity in New Hampshire, we're sure living in interesting times.

Friday, January 15, 2010

Electricity in NH - No choice for residential customers (continued)

I did a recent post on electricity choice in New Hampshire and I mentioned that for residential ratepayers, New Hampshire is stuck in a restructuring limbo. The regulatory framework for residential choice is ready to go, but so far there are no power marketers willing to offer energy to residential customers.

The problems from our current lack of choice fall into two buckets. The first has to do with utilities having to guess the future in hopes of securing reasonable and stable electricity rates for consumers. The second potential problem revolves around PSNH's continued operation of generating resources and the allocation of costs for those resources to various types of ratepayers.

Do you go with the oil pre-buy option, or do you like to let it ride?

Reasonable people can disagree on the extent to which utilities should pre-buy their customers' electricity. Should utilities mostly use long term power purchase agreements? Should they favor shorter term agreements? Should they just roll the dice and buy power on the spot market? New Hampshire's limited electricity choice forces residential ratepayers into a one-size-fits-all approach that's a little like requiring everyone to enter into an oil pre-buy agreement. This may be ok for some, but it's probably not right for everyone.

The idea of paying a little extra to secure a steady supply of a commodity at a reasonble price is often used in business. During the 2008 oil price surge, Southwest Airlines was very adept at protecting itself from oil price increases by correctly hedging their jet fuel needs on the futures market. Meanwhile other airlines were forced to buy fuel at market prices, and they paid dearly. Still, this guessing game is far from a certainty and for each success story, there's a case of a company betting wrong or paying higher costs with no benefit.

Should your electric utility be an active or passive investor?

A hedging approach doesn't always make sense and it often increases costs. Another analogy comes from the world of stock market investing. There are two schools of thought in investment management, an active approach and a passive or index investing approach. The passive approach says that even professionals can't "out guess" the market and over time, the average performance of active managers will be no better than the market overall. In fact, research suggests that average returns from active management may be even less than market returns because of the added costs of trying to beat the market. These passive or index investing adherants think paying active managers is a bad idea that just pads the pockets of investment advisory firms.

This same debate could also be applied to procurement of electricity and is another reason why establishing a strong system of retail electric choice is important. Some folks may want to take a passive approach to energy procurement and avoid bets on future prices. Others may be confident that analysts can successfully predict future market conditions. They may want their energy provider to place bets on future electricity prices in hopes of getting lower rates or greater rate stability.

There are plenty of arguments for both sides in the passive vs active electricity procurement debate. To be sure, securing financing for a new power plant depends on long-term power purchase agreements to help mitigate risks, so it wouldn't be in anyone's interest for these contracts to go away completely. Still, regardless of which side is right, even without retail choice, regulators could require transition energy suppliers to separate out their "active management" activities and perhaps create multiple rate programs (offered by a single utility) to allow customers to chose the approach that works best for them.

Who should bear the cost and risks of upgrades to legacy plants?

There's another issue with New Hampshire's lack of residential energy choice. It has to do with PSNH's continued operation of "grandfathered" electriciy generating plants and revolves around who bears the cost and risks of upgrades to these plants. Under NH's original restructuring plan, PSNH divested itself of many generating assets, but was allowed to retain some older plants that had limited life left in them. Merrimack and Schiller stations (both coal plants) are two examples. The intent was that eventually, PSNH would retire all of their generating capability and leave power generation to non-utility independent power producers. Unfortunately, or perhaps fortunately, PSNH has been able to keep their legacy coal plants running at a reasonable cost. They've also done some upgrades over the years such as converting one of Schiller's coal units to biomass.

The result of this, so far, seems to be that PSNH's ownership of these legacy plants is actually helping to keep electricity costs down. Since these old plants are already paid for, burn mostly inexpensive coal and were built when regulations were less stringent, they're generally cheap to operate and couldn't easily be replaced. Although some would argue we're actually paying an additional environmental cost for these plants' electricity due to their high carbon emissions.

Merrimack Station and the unpriced "coal" option

Although things may have gone alright so far, additional issues arise as more expensive upgrades are done to these plants. For example, PSNH was mandated by the NH legislature to install a "scrubber" at the Merrimack Station plant to reduce the plant's mercury and sulphur emissions. Everyone agrees that lower sulphur and mercury emissions are a good thing, but as always, the question is - who will pay for it and who will bear the risk?

And here's the real problem. No one knows what's going to happen to the economics of coal-based power generation over the 15-20 year life of the $457 million scrubber project. If coal prices stay low, carbon emissions don't get priced, and oil and natural gas skyrocket, the scrubber project will seem like a great investment. We'll be glad we kept the plant going. On the other hand, if coal prices increase, natural gas prices decrease, or carbon emission prices skyrocket out of control, the scrubber project is likely to be a loser and the economics of using Merrimack Station for power generation could become very tenuous.

Nothing new there. Everyone knows there's risk and uncertainty with any large capital project. The problem shows up when you look at how each scenario is likely to play out given our current regulatory framework and competitive market. If the scrubber project turns out to be a good decision, PSNH will be able to offer lower rates and business customers, since they have a choice, are more likely to choose PSNH as their energy supplier. If the scrubber turns out to be an economic dud, and coal plants are shuttered because they aren't economical to run, business customers can just choose an energy supplier other than PSNH - one that's not saddled with the high costs of the scrubber. In either case, residential ratepayers are stuck buying their power from PSNH at whatever price they offer, even if that price includes the costs of an uneconomical scrubber. In finance, the ability to "choose the best option after the fact," without paying for it is referred to as an unpriced option. It's a heads businesses win, tails residential ratepayers lose situation.

Just to be sure I wasn't missing something, I checked in with the folks at New Hampshire's Office of Consumer Advocate. They brought two additional points to my attention that I hadn't considered. First, if PSNH's rates for residential ratepayers do increase above the competition due to the scrubber, it's possible that a competitive supplier will step in to sell power to residential ratepayers, since they'd be able to beat PSNH's prices. Another consideration is that if the costs of the scrubber are not being fairly allocated, the PUC and legislature may intervene and introduce stranded costs recovery rules to more fairly allocate the costs of the scrubber between residential and business ratepayers.

Sunday, January 10, 2010

Antifreeze - What's a dog's life worth these days?

Bailey - our 6 year old Brittany

A few weeks ago I did a post about a proposal to require residential sprinkler systems in New Hampshire and I tried to find estimates for the "cost per life saved" for these systems in order to help put the cost into perspective.

So naturally, when I saw this AP report at about legislation to require a bitter-tasting additive in retail antifreeze sold in NH, my first question was - What's the cost per pet life saved?

If you've been wondering this too, fear not. I'm on it!

To compute the cost, I decided to go with a national estimate, since NH specific numbers were too hard to find. First, I learned that as many as 10,000 pets die each year in the US as a result of antifreeze poisoning.

Next, I found a rough cost estimate from this 2005 US Senate committee report on the issue:

Under S. 1110, if the CPSC determines that the use of the bittering agent in engine coolant or antifreeze would have no adverse effects on the environment, coolant and antifreeze manufacturers would be required to add the agent to certain product mixtures. The bill would exempt coolant and antifreeze distributed to original manufacturers (such as motor vehicle manufacturers) and garages that purchase wholesale engine coolant or antifreeze for purposes other than retail sales. According to industry sources, about 160 million gallons of coolant and antifreeze are sold in the U.S. retail market each year. Industry and government sources indicate that adding the bittering agent to product mixtures would cost manufacturers less than $0.03 per gallon of coolant or antifreeze. Furthermore, the industry expects to incur some costs associated with upgrades necessary for storing denatonium benzoate at manufacturing plants. Industry sources estimate such costs to fall between $50,000 and $70,000 per plant. Based on those data, CBO estimates that the costs associated with this mandate would not exceed $6 million per year.

This is all pretty rough, but it should be good enough for a ball park estimate. The CBO cost figure of $6 million per year along with an (admittedly high) estimate of 10,000 pets saved per year, yields a cost per pet saved of around $600.

This is probably a best case scenario, since there's concern that the bitter tasting additive may not deter all pets from drinking antifreeze. Also, most of these initiatives exempt manufacturers and garages that purchase antifreeze in bulk, so some cases of poisoning will likely still occur from leaks and improperly disposed untreated antifreeze.

I found conflicting data on whether many people are killed by antifreeze poisoning in the US. One report indicated as many as 1400 children are treated for poisoning each year, however reports of deaths seem rare. In fact, according to this site, most of the recent human deaths from antifreeze were intentionally self-inflicted or due to homicide.

New Hampshire's proposed antifreeze legislation comes on the heels of similar initiatives in several states including Oregon, Washington, New Mexico, Arizona, Tennessee, Vermont, Maine, Virginia and California.


Tuesday, January 5, 2010

Electricity in NH - Retail electricity choice has fallen short

Screenshot of NH PUC website on electric power choice

I've blogged about the general framework for electricity market restructuring in New England and I've touched on some of the specifics for New Hampshire. Overall, our electricity restructuring effort seems to be working out reasonably well. Unfortunately though, for New Hampshire's residential electricity customers, restructuring is a story of unfinished business.

New Hampshire's restructuring model sought to eliminate the monopoly that local utilities had over electricity generation, distribution, and delivery. Under the new approach, the maintenance of the electricity distribution and delivery system would still be handled by a monopoly utility, but the provision of virtual "energy" to ratepayers would be the responsibility of independent power marketers. The plan follows an approach similar to the telephone long distance model. Power marketers would offer retail electricity customers various energy rate plans and would then contract with power generators or procure power using ISO-NE's bulk electricity trading markets.

PUC has been unable to bring residential choice to NH so far

Although NH regulators tried to open up electricity markets to consumer choice, their attempts have failed so far, at least for residential customers. Currently, business ratepayers in New Hampshire can choose from around 10 or 12 energy suppliers, but residential ratepayers have no choice and seem to be permanently stuck with their "transition" energy supplier (aka their old monopoly power company).

Even though residential electricity customers are stuck with their monopoly energy supplier, you'd never know that from reading the NH PUC's website on electricity choice. The site talks about the benefits of choice and even lists several competitive suppliers. Unfortunately, there's not a single mention anywhere on the site that none of the competitive suppliers service residential customers.

What retail choice might look like

For examples of some potential benefits of retail electric choice, consider the market in New Hampshire for home heating oil. Folks in New Hampshire that heat with oil have lots of choices. We can stick with one company and sign up for automatic delivery. We can call around each time we need a fill and get the best rate. If we're concerned about the environment, we can choose one of the new biofuel offerings. Finally, if we're worried about the variability of oil prices throughout the winter, we can choose a rate-lock plan. With retail electricity choice, electricity consumers could have many of these same options.

Texas gives us an example of how electricity choice might have turned out. To be sure, Texas is no shining star of ultra-low electricity rates, but their electricity choice model is well developed and shows us a glimpse of how things could look in New Hampshire. This website (use zipcode 75001) shows a list of rate plans available to texas electricity consumers. For a comparison datapoint, PSNH currently charges around 9 cents per kilowatt hour for energy.

Pennsylvania has also developed retail choice for electricity consumers. The state's Office of Consumer Advocate website has information for consumers about the state's retail electricity choice program, along with several price comparison charts that show the offerings available in different parts of the state.

The retail electricity choice programs in Texas and Pennsylvania offer variable pricing plans, rate lock plans, and even green-energy plans. There seems to be something for everyone. To be sure, some folks may find this all too confusing and might rather let their state PUC figure it all out for them. Unfortunately, the PUC is forced to create a "one size fits all" rate structure and can't possibly make decisions that are optimal for everyone.

Where should New Hampshire go from here?

In the end, I think residential electricity choice would be a good thing and I hope we get it here in NH. Sure, there will always be consumers who are under-served by having to fend for themselves and some may prefer to have someone else make the choice - and take the blame for making the wrong choice.

In addition, there will always be studies that show restructuring has lowered rates or caused rates to skyrocket. It just depends on the time period chosen and what's been happening to fuel prices (like natural gas and coal) over the period evaluated. As I've said before, you can't evaluate the efficacy of restructuring just by taking a snapshot of electricity rates. You've got to consider the risk model and the generation mix and evaluate rates in that context.

Still, in New Hampshire, our regulatory framework is set up for retail choice, and in order for our framework to function properly, retail choice must be established for residential electricity consumers. Without a choice, residential ratepayers are at a distinct disadvantage compared to businesses and consumers may end up getting a raw deal.

If an effective retail market for energy won't form on its own, the NH PUC will have to act to correct the situation. That could mean incentives to create more retail offerings, or we may need a complete restructuring of how retail electricity rates are set. In either case, leaving NH ratepayers in this restructuring limbo seems like the wrong approach.


Wednesday, December 30, 2009

Electricity in NH - Did restructuring cause higher prices in New England?

Seabrook Station Nuclear Power Plant - Seabrook, NH

With more snow coming and the faint hum of the oil burner in the background, it seems like a good time for a follow-up in my electricity restructuring series. Lately, there's been a growing concern that restructuring is not working and perhaps we should re-evaluate our current "simulated market competition" approach to electricity markets.

In Connecticut, some state officials want to return to the old regulated monopoly model. The justification is that electric rates in Connecticut are higher than nearly anywhere else in the country and they say that's proof that restructuring has failed. These officials point out that the lowest electricity prices are often found in states that still use the regulated monopoly model for electricity generation.

Correlation does not imply causation

In light of these assertions, I'm reminded of a favorite phrase of economists, scientists, and statisticians - Correlation does not imply causation. In other words, when two things are related, you can't just assume that one caused the other. Just because New England has high electricity rates and has restructured their electricity markets doesn't mean that restructuring caused the high rates.

In fact, in Connecticut, and in New England, electricity rates have long been higher than average rates in the rest of the country. Generally, the states where electricity restructuring took hold were the states with the highest rates to begin with. That makes sense since we New Englanders have a pretty strong "if it ain't broke, don't fix it" sensibility. If electricity rates in New England weren't broken, my guess is we'd have left well-enough alone.

It turns out that the main explanation for higher electricity rates in New England is that for lots of reasons, we decided to generate our power with more expensive fuels like nuclear, natural gas, and oil and we don't use as much cheap coal as other regions. In the US overall, inexpensive coal is used to generate almost half of all electricity, while in New England, it's used to produce only 12%. Nuclear, gas, and oil together produce almost 70% of electricity in New England, but only 40% nationally. Our focus on fuels such as nuclear and natural gas keeps our air cleaner, and may be necessary due to our region's resources, but it comes with a cost.

Power Generation by Fuel Source in the US (EIA Report, slide 20)

Connecticut legislators also have another beef with restructuring. They argue that ISO-NE's marginal-price-based bulk power markets cause ratepayers to overpay for electricity. They say that paying all generators the price that "clears the market" and matches up supply with demand gouges consumers and sends excess profits to lower-cost energy producers. There may be something to this concern, but the challenge is to find a solution that can correct the problem without introducing even greater inefficiencies.

Marginal pricing - it's just how free markets roll

Supply and demand intersect at market clearing price and quantity

Under marginal pricing, the market price for everyone is set by the last unit of a good that's needed and supplied in the market. All suppliers (power generators) are able to sell their output at that last or marginal price. If the cost of supplying the last unit is roughly the same as the cost of supplying all other units, this isn't a big deal. However, if the marginal cost of production (the cost to make each additional unit of output) is sharply increasing, producers who have lower costs get excess profit because they get to sell their inexpensively produced output at the market price set by the last unit produced. In electricity generation, low-cost coal based producers can get a bonus because the marginal price of electricity is usually set by more expensive natural gas generators. Under a regulated monopoly model, utilities could only recover their actual cost of generating the power needed, plus a fixed profit.

Although these inefficiencies can be real, in a free market system, most prices are set using marginal pricing. Marginal pricing is how the market figures out the price of a gallon of gasoline, the price of a home, and the price of a new TV. Sure, there are other approaches, but in reality, once you decide that a market-based pricing scheme isn't good enough, you're on the hook to out-design the market and that's usually tough to do. Reverting to the regulated monopoly cost-plus approach has its own inefficiencies. The question boils down to which "synthetic" market structure can achieve the best result.

Generating capacity - do you come from a land of plenty?

One important step in assuring that the cost of electricity is reasonable is to assure that there's enough generating capacity. Under perfect, free-market competition, there would be hundreds of firms entering and exiting the power generating market and the supply of generating capacity would naturally meet up with the demand. Unfortunately that didn't happen with power generation in the early days of restructuring, and some regions experienced serious electricity shortages as demand grew faster than supply.

Since the market didn't naturally build the needed capacity, regulators tweaked things by creating a system of "capacity payments" to encourage power generators to build and maintain enough capacity to serve the market's needs. That sounds reasonable, but as with much of restructuring, getting the incentives right has been tough. In practice, capacity payments aren't just paid to owners that build new plants, they're also paid to existing power plant owners. Many economists believe this is inefficient and raises prices more than is needed to assure adaquate capacity.

In the end, it's all about the risk

While it's vital for restructuring that regulators get the market mechanisms and incentives right, the more I learn, the more I become convinced that a huge part of the equation is understanding how risk is allocated, and how we'd like it to be allocated. Exactly how should the risks of a new coal scrubber, wind plant, or nuclear power plant be allocated? Who should pay if things don't turn out as planned? Who should profit if things go better than planned?

Advocates of the regulated monopoly approach suggest that because regulated utilities have a lower cost of capital, they can offer a less expensive model for power generation. IMO, this view is incorrect. Unlike merchant power generators, utility power plant owners are basically risk pass-through entities. They have lower financing costs because the risk of their capital projects is passed on to ratepayers. Sure, there are some benefits from the certainty of a captive consumer base, but most of those benefits can also be enjoyed by merchant generators using power purchase agreements to pre-sell their output. In the end, there's really no free-lunch in terms of cost-of-capital. The power plants that regulated utilities build are every bit as risky as those that merchant generators build. It's just a question of how the risk is allocated and who pays if things go bad.

It seems that trying to figure out if one regulatory scheme is better than another without delving into the risk model is like trying to decide if bonds are better than stocks by looking only at last month's returns. Unless you've uncovered what the risks are and who's on the hook for them, the pricing at any instant could be a mirage.

So, did restructuring cause higher electricity prices in New England? Personally, I don't think so. There have certainly been challenges in getting the market structure right, and these could have increased costs some. Still, I don't see any obvious signs of market failure either. To me the key in all this is to get the incentives and the risk sharing right.

Developing a robust electricity generation and delivery system that can meet our needs today and in the future involves taking risks. The ultimate question is this: How much risk do we, as electricity consumers want to transfer onto investors and how much are we willing to shoulder by ourselves? IMO, a purposeful allocation of risks and rewards should drive electricity market structure and getting that right will lead to the best outcome for consumers and for our economy.

Wednesday, December 23, 2009

Portsmouth based carbon capture firm completes pilot

Coal fired power plant in Bow, NH

I came across a recent report by SeacoastOnline about a company in Portsmouth called Powerspan that's doing some pretty cool work with carbon capture technology. Apparently, the firm just completed a pilot program on a 1 megawatt coal plant in Ohio that helped prove out their technology and lay the groundwork for a future commercial deployment.

Carbon capture is a technique that helps clean up the output from coal-fired power plants. In NH, PSNH is working on cleaning up emissions from our largest coal plant, Merrimack Station, but this effort will only remove mercury and sulfur dioxide, not carbon.

As I've mentioned before, for lots of reasons, coal is likely to be an important part of our energy mix for decades to come. Anything we can do to economically clean up the output from coal power plants is a good thing. It's neat that we've got a company right here in the seacoast of New Hampshire that's helping to solve this tough worldwide problem.

Although this is promising technology, Powerspan still has some big work ahead of them, especially in terms of economics. The firm's press release on the pilot indicates that using their technology will cost around $50 per ton of carbon removed from a coal plant's output. While this is apparently a breakthrough compared to competing carbon capture technologies, $50 per ton is still nothing to sneeze at.

Some very rough power generation costs (using $20 per ton for coal emissions)

For some perspective on that cost, consider the data in my power generation economics post from last July. In one of the later graphs, I priced carbon emissions at $20 per ton to show the impact of emissions on the economics of coal generation (see graph above). Generating a megawatt hour of power using coal can easily produce a ton of carbon emissions, so adding in a $50 per ton charge instead of $20 would significantly increase the cost of power from coal. In fact, adding $50 a ton for carbon capture would move coal's fuel and operating cost from 4.5 cents to 7.5 cents per kWh in the graph above. That could make coal uncompetitive versus other approaches.

Still, we shouldn't be too negative about the costs of carbon capture. The technology is still in its infancy and we're likely to see major breakthroughs along the way. Also, as long as we're subsidizing other emerging clean power generation technologies like wind and solar, it seems only right that carbon capture is included in the mix.

IMO, we should think of investing in power generation technology the way we think about personal investing. We should take a "portfolio" approach and diversify in order to minimize our risks and maximize opportunity. Even though wind and solar are showing great promise right now, we shouldn't put all our research eggs in one basket.

It's going to be a long haul to get to a cleaner energy future and I don't think anyone really knows what that future will look like. Personally, I'm glad to see these local folks working hard and smart to help us find the best way there.