Competitive Transmission Providers?

One of the hot topics in California at the moment is the CAISO’s apparent favoring of incumbent utilities in approving new transmission projects.  Proponents of alternative transmission system developers claim that the ISO’s purported preference diminishes competition and ultimately increases cost to consumers.  They claim that they can build transmission facilities better, cheaper and faster than the big incumbent IOUs (Pacific Gas & Electric, Southern California Edison and San Diego Gas and Electric), and that the ISO is unfairly discriminating against the competitive developers just to keep the utilities happy.  If you look back at the development of non-utility generation and the merchant generation business, the competitors have a good point.  Over the last dozen years or so, the competitive market has put downward pressure on generation development and operating costs, shortening the development process, and shifting risk from the utility ratepayer to the developer.  This has been good for the generation business so surely it would benefit the transmission side of the business.

There is no doubt (except maybe in the “Southern” states and among the APPA) that the competitive generation business has been good for consumers, so we should strive to bring competition to other aspects of the business as well, right?  Maybe not.  The generation business clearly benefited from reduced costs and increased efficiencies brought about by competition.  However, one of the primary reason was not increased efficiency compared to bloated vertically integrated utilities (though it certainly was), but a completely different profit paradigm.  Merchant generations make their profits from selling energy at prices higher than their costs.  The most effective way to increase profits is thus to reduce costs and increase efficiency over both the short and long-term.  This encourages practices like hedging gas price risk and minimizing heat rate.  Utilities, on the other hand, were able to pass through “reasonable” expenses and recover a specified return on equity.  In other words, the more they invested in rate-base the more earnings they were able to return to their shareholders.  This peculiar “regulated cost of service ratemaking” was a function of the “natural monopoly” compact that was developed by Samuel Insull and implemented in the early 1900s. It was very effective for most of the century as electrification spread and marginal costs decreased.  But when competition is an option it makes little sense to reward companies for convincing regulators that they should build more stuff.

Unfortunately, that’s where we are in the transmission part of the business.  Because of the inter-connected and integrated nature of the transmission grid and the variety of impacts a transmission upgrade may have, it’s not reasonably feasible to charge for usage.  Also, the operating costs of a transmission line are trivial compared to the capital cost to build it, so that reduced operating costs have an insignificant impact.  Then there’s the fact that transmission covers a huge geographic area, making franchise agreements and access to eminent domain important characteristics.  So what exactly is it that “merchant” transmission developers have to offer that make them better suited to develop transmission projects?  Virtually all rely on the “go to FERC and get a guaranteed rate of return approved and have the ISO include the costs in its transmission rates” model, which bears a very strong resemblance to the utility model they’re proposing to replace.  Some might argue that it’s just a different set of shareholders.   

Solar PV - Dis-economies of Scale?

Some recent announcements from Southern California Edison (SCE) appear to warrant more than a little head scratching.  SCE recently announced contracts for the purchase of energy from two different sets of sources.  On January 31, 2011, SCE filed the contracts it had announced in November for 239 MW (567 GWh/year) of solar PV projects resulting from its Renewable Standard Contract (RSC) program.  The 20 projects are all between 4.7 and 20 MW, are for 20 year terms, are scheduled to come on line between April 2013 and April 2014 and are all priced  below the 2009 Market Price Referent (MPR) ($108.98 for contracts starting in 2013 and $112.86/MWh for contracts starting in 2014).  This would certainly appear to support assertions that PV prices are coming down dramatically and could soon be competitive without massive subsidies. 

Also in January, SCE announced that it had executed seven contracts totaling 831 MW for solar PV resources between 20 and 325 MW each, coming on line from 2103 through 2016.  These contracts are all priced ABOVE the very same MPRs that the smaller RSC contracts are below.  How could it be that smaller projects using the same technology are less costly on a per unit basis than larger projects?  I’ve no idea, and not being privy to the confidential pricing terms of the contracts, I can only guess.

The first issue is one of scale – PV installations in the multi-MW size range all pretty much use the same panels, inverters, transformers and other equipment.  A larger project that interconnects at transmission voltage (115-230 kV) will require an extra step of transformation and more costly interconnection facilities than a smaller project that interconnects at distribution voltage (12-33 kV).  Review of SCE’s filing of the RSC projects does show that they are almost all interconnected at distribution voltage.  Since distribution facilities cannot handle anything much larger than 20 MW (if that), larger installations would have a “dis-economy” of scale based on interconnection voltage.

Another issue relates to parcel size and permitting.  At roughly 10 acres per MW, a 200 MW project requires a huge tract of land – over three square miles!  Such a project is likely to get much more attention in the permitting process than a 10 MW project that “only” needs about 100 acres.  It is also more likely to have a significant environmental impact and require both more complex permitting and greater mitigation costs.  Here again size is a dis-economy.

Then there is the cost of capital.  A 200 MW project will cost upwards of a billion dollars.  Raising that much capital probably incurs a higher cost and may also require a higher percentage of equity to secure debt financing.  Both would tend to increase the unit cost of the project compared to smaller projects.

Then there is the PPA negotiation process.  SCE developed the RSC (and the CPUC approved the related Renewable Auction Mechanism, aka RAM) as standardized contract with limited room for negotiating terms and conditions.  Bidders are required to bid on price alone head-to-head against other potential projects for a contract.  They are likely to offer their lowest and best price into the solicitation. Large RPS contracts, on the other hand, often require months of negotiation and in many cases go through upward pricing adjustments before they come to fruition.  How much this adds to the final price is hard to say.

The conclusion drawn from these interesting submissions is that an increased reliance on distributed PV generation – whether on rooftops, vacant lots, or surplus agricultural land – may not prove to be more costly than the huge projects built in the middle of nowhere.  Of course, the smaller projects do not require the massive transmission projects needed to export power from the middle of nowhere.  That means less utility ratebase – often receiving incentive rates of return – available to benefit IOU shareholders, the very same IOUs that are negotiating PPAs with the massive projects.  Interesting coincidence.

2011 Predictions

It's time once again to prognosticate expected changes to the coming year.  With a "new" governor in Sacramento, things could get interesting. However, Governor Brown can probably be expected to stay the course regarding renewables policy, though he's less likely to veto "California-centric" 33% RPS legislation.  His stated energy policies are virtually identical to his predecessor’s, so there is little reason to expect significant changes, particularly as he focuses on resolving the state’s fiscal crisis.  Brown does have two CPUC Commissioner positions to fill, as well as one CEC Commissioner and two CAISO Governors.  How soon he fills those positions – and who he appoints – should give an idea of whether he intends any early redirection of regulatory energy.

CPUC

Departed Commissioners Bohn and Grueneich represented the “extreme” positions on the CPUC (though with most Commission votes at 5 to 0, the distance between the extremes is not that great).  The Governor’s choices to replace them should give an idea of whether he plans a significant shift in CPUC policy.  Since the Commission has generally mirrored the Governor’s stated energy policy, there is no reason to expect any significant changes.  The current flow of events does, however, suggest some potential opportunities and challenges in 2011.

Resource Adequacy 

The CAISO has started the ball rolling toward reconsideration of some kind of centralized capacity market by asking the Commission to consider load following characteristics for resource adequacy.  The need to develop renewable integration products and maintain some level of viability for non-contracted conventional generation resources, should provide new life for a capacity payment mechanism.  The key to consideration of a capacity mechanism will be in emphasizing the need for resources available to integrate renewables.  If carefully handled, acknowledging the need for payment mechanisms to offset energy market price reductions could provide basis for new capacity market, though it will take 18 to 24 months to get anything adopted.

Long Term Procurement Planning

The first quarter will be the time to establish an out-of-the-box approach for new generation development.  IOU plans are likely to show minimal need for new resources.  Combination of slow economic recovery - less load growth[1], optimistic RPS and CHP forecasts - 2000 MW of new CHP seems excessive, IOU PV programs and RAM impacts are all likely to focus resource acquisition on replacing OTC units and supporting renewable integration.  Absent an explicit requirement to replace OTC generation with new flexible resources, the IOUs’ bundled customer service plan is likely to call for virtually no new gas-fired generation.  To the extent that OTC resource owners are able to come up with some kind of voluntary OTC replacement plan, they may be able to use it to justify new generation.  Whether the result will be a specific OTC replacement program or some kind of RFO “bonus” for OTC replacement remains to be seen.  This could be the year that a coherent OTC replacement policy gets serious consideration.

Smart Grid

A Smart Grid administrative structure will continue to develop.  Smart Meter brouhaha will dissipate as actual radio emissions impacts are understood.  Some sort of wired option - using landline telecom, perhaps - may become available as alternative for complainers, at their cost.  The idea of making smart meter installation optional is not likely to get much traction unless PG&E bungles things yet again.  Continued talk of smart grid as new killer app without any real consumer impact.  IOUs (particularly SCE) will push for money for grid improvements that improve reliability and operations.  ISO will continue to implement small changes, third party data entities will continue to participate with little in the way of meaningful business opportunity.

Electric Vehicles

The impact of EVs on the grid will remain trivial.  Price point and range limitations are likely to restrain enthusiasm.  The key to EV success may hinge on development of “battery service providers” that will facilitate battery swapping or other fast “refueling” options and change the equation for EV ownership.  Shake out will most likely evolve over the next two to four years as winning battery design and business models become apparent.  Long-term battery standardization and servicing model will be key to EV success.  Regulatory success will include the development of sub-metering rules that will not rely on utility ownership or control.  So far, the CPUC appears to be headed in the right direction – not attempting to put competitive EV service providers in the same category (and with the same restrictions) as electric utilities.

Renewable Portfolio Standard

This could be the year that the economic wisdom of the 33% RPS requirement begins to be questioned.  The combination of a good hydro year, continued low natural gas prices and PG&E’s negotiated General Rate Case settlement will keep current electricity prices from getting out of hand and igniting a "ratepayer revolt."  However, the next RPS solicitation (expected in the first quarter of 2011) should result in a revised – and reduced – Market Price Referent (MPR) that will make more renewable projects appear uneconomic.  A couple more large RPS projects will fail, causing much hand-wringing and questioning of the RPS paradigm.  Some big solar projects will begin construction, but by the end of the year California will not yet lead the world in installed solar generation capacity (but could by the end of 2012).  PV prices will come down a bit for smaller projects (sweet spot likely to be 5-20 MW thanks to IOU purchase programs).  33% RPS may get adopted by legislature, though there will finally be some questioning of the cost, particularly as gas prices - and MPR - continue to remain low.  Success of RAM and PV programs combined with failures of large projects may cause some questioning of reliance on huge projects.  It is possible that IOUs will finally decide that RPS prices are too high and exercise right to say so, slowing RPS procurement, but that probably won’t happen this year.

RECs will finally be adopted, though 33% legislation could muddy waters.

Energy Storage

“New” storage technologies will get a boost from the CPUC’s recent rulemaking (R.10-12-007) but only in how much it's talked about.  Policy development may be driven somewhat by PG&E’s pumped storage application.  Battery storage coordinated with EV development could begin to gain some steam.

Utility Generation Projects

PG&E's Manzana project will get a favorable PD and be approved.  If it is not, the language regarding ratepayer-funded versus developer-funded risk may be a useful stone to hurl at the CPUC's hybrid resource development paradigm.

SCE will get to build peaker in Oxnard.

CPUC Transmission Authorization

Questions will begin to arise about need for transmission projects as more huge RPS projects get cancelled anticipated delay in transmission development as projects look for ways to start building.

CEC

The CEC Infrastructure assessment will turn into a typical CEC activity - interesting but of minimal policy impact.  It will likely make use of information available from other sources and conclude that transmission is needed to access renewables.

The number AFC cases under consideration will be significantly reduced as the rush for ARRA funding ends.  Expect no more than 6 or so active projects once moribund projects are removed.  Several solar thermal projects with PPAs will need to either begin the siting process, convert to PV or fade away.

CAISO

The CAISO is in the process of moving into its new headquarters which should keep it fairly internally focused during January.  They can expect some push back on the 2011 Transmission Planning Process, with questions about transmission projects included/excluded.  Expect some changes to the transmission plan as RPS projects rise and fall over the year.  It will become more and more obvious that out of state RPS projects likely to be more cost-effective and feasible than reliance on in-state resources.  If the legislature once again passes 33% RPS legislation that focuses on resources in California, it will further hamper the IOUs meeting the RPS requirement and may kick off the “it’s too expensive” argument.  Issue of WEC-wide balancing market likely to increase in importance, though implementation will be slow.

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[1] The CEC issued a revised Short-Term Demand Forecast that estimates the CAISO peak demand will be some 2,400 to 2,700 MW below the 2009 forecast.  Current forecast values are comparable to the forecast in the 2006 LTPP decision (D.07-12-052).

Does Shale Gas Portend End of Fixation with Renewables?

A recent 60 Minutes segment on shale gas drilling started me thinking about our energy future, wondering if this latest evolution in natural gas production could mark the beginning of the end for the “renewable energy at any cost” policies that constitute the current conventional wisdom among regulators in the energy industry.  The fascination with renewable resources is due to fall out of favor sometime soon, the only questions are what will drive it and when it will happen.  Looking back at developments over the last 40 years suggests that we’re about due.  In the 1950s and 1960s, the focus was on building larger and larger central power plants that relied on inexpensive fossil fuels to generate electricity at lower and lower unit costs.  In the 1970s, as petroleum prices became more volatile, nuclear power became the choice for the future, promising power at prices “too cheap to meter.”  Nukes fell out of favor in the 1980s following the Three Mile Island and Chernobyl accidents, in many cases changing from a favored resource to being severely restricted or even banned.  PURPA became the mantra of the next decade or so, as qualifying facilities using renewable fuels or cogeneration (aka combined heat and power) became the wave of the future.  As increases in energy efficiency reduced load growth and generation surpluses became an issue in the 1990s, there was a move in California to renegotiate the more costly PURPA contracts and shut down the unneeded generation.  That further evolved into the development of competition in the generation of electricity and the “de-regulation” that took place in the last half of the 1990s.  The California energy crisis of 2000-2001 gave relying on markets a bad name, just as the latest environmental trend (global warming) and the latest petroleum price spike increased the popularity of renewable resources and brought us where we are today.

What is it about shale gas that suggests that it could presage the end of the renewable decade?  The simple answer is cost, particularly as it applies to environmental impact and energy security.  

Environmental Impact – Natural Gas and Global Warming

One of the primary justifications for renewable generating resources is that they mitigate global warming by generating electricity without emitting any greenhouse gases (GHG).  Wind and solar, the most widely considered renewable resources, directly produce zero GHG.  The fossil fueled generation that these renewable resources would replace do produce GHGs in the following amounts:

Table 1 – GHG Production
Source	Heat rate	GHG/MMBtu	Ton GHG/MWh
Coal	9	.097	.873
Nat Gas CCGT	7	.053	.371
Nat Gas CT	10	.053	.53

By displacing coal, renewable resources reduce GHG production by about .873 tonnes/MWh.  If replacing natural gas combustion turbines or steam plants, renewable would reduce GHG production by about .53 tonnes/MWh, comparable to the GHG reduction that would result from displacing coal with CCGTs.  Because coal currently generates 49% of the electricity consumed in the US (Table 2), replacing it with a combination of wind and solar would require 250,000 to 350,000 MW of new wind turbines and 400,000 to 600,000 MW of new solar generation.  Replacing coal with CCGTs would require roughly 300,000 MW, and increase current natural gas consumption by about 60% (~14,000 BCF/year) to three times the amount of natural gas currently used to generate electricity.  The potential for significant increases in natural gas production from shale production could make natural gas a more viable alternative in the future.

Energy Security

Another argument for renewable power generation is that it reduces reliance on imported oil.  The only problem is, that’s not true.  Table 2 shows the net generation by energy source in the United States for 2007.  AT 1%, imported oil is a trivial source.  While the US does import about 16% of its natural gas, virtually all of it comes from Canada.  

Table 2 – US Electric Generation Sources, 2007
Fuel Source	GWh	% of total
Coal	2,016,456	49%
Petroleum liquids	49,505	1%
Natural Gas	896,590	21%
Nuclear	806,425	19%
Hydroelectric	240,614	6%
Other renewable	105,238	3%
Other	41,918	1%

Source:  EIA Net Generation Table

Increasing renewables does little to improve energy security.  Indeed, to the extent that new renewable generation equipment is manufactured outside the country, it creates a different security concern – increasing trade deficits and increased reliance on foreign sources for energy production.  Considering that roughly half of the cost of generating with natural gas is for fuel or O&M, it could be argued that gas is more likely to encourage investment in the US than the renewable options.

Economics – Energy Cost

Regardless of how inconvenient (or truthful) global warming concerns may be, when all the costs are included, today’s favored renewable technologies are a very costly way to reduce GHG.  Consider the examples of off-shore wind and “middle of the desert” solar.  For the first, we can look at the Atlantic Wind Connection.  This $5 billion transmission project is proposed to deliver about 6,000 MW of off-shore wind energy to market.  A revenue requirement of about 20% of the development cost, combined with an expected capacity factor of 40% for the wind generation, would result in a transmission cost adder of about $47/MWh just to deliver the wind generation to the grid.  That's on top of the cost of the generation itself.  According to the California Energy Commission Comparative Costs of California Central Station Electricity Generation report, offshore wind resources cost about $4,000/kW, for an annual fixed cost of about $800/kW year.  Assuming O&M cost of about $5/MWh and a 40% capacity factor, that’s about $228/MWh, plus the gen-tie cost of $47/MWh, results in a delivered cost of $280/MWh.  This does not include the cost of generating capacity that must remain available for when the wind isn’t blowing. 

We can use a slightly different method for evaluating “middle of the desert” solar thermal resources.  Using filings by the large California IOU’s, it is possible to estimate (actual contract values are confidential) the cost of large central solar thermal power plants.  A “bid price” of $120/MWh, adjusted for Southern California Edison’s time of delivery factors, produces a payment of $204/MWh.  Add in SCE’s Tehachapi Renewable Transmission Projects – total cost $2.06 billion, providing 4,500 MW off-take capacity, assuming 25% capacity factor for solar – with a cost of $41/MWh, the total cost for this renewable resource is $245/MWh. 

A natural gas-fueled combined cycle gas turbine (CCGT) plant would cost about $1,300/kw to build.  It would have a 7 MMBtu/MWh heat rate, operate at a 75% capacity factor and require about $5/MWh for O&M.  At a natural gas price of $5.00/MMBtu, the total delivered electricity cost is about $80/MWh.  A new combustion turbine (CT) plant would cost about $1,000/kw to build.  It would have a 10 MMBtu/MWh heat rate, operate at a 25% capacity factor and require about $5/MWh for O&M.  At a natural gas price of $5.00/MMBtu, the total delivered electricity cost is about $146/MWh.  Table 3 considers the overall cost impact of GHG reduction. 

Table 3 – Relative GHG Reduction Cost
Technology	Cost/MWh	T CO2e/MWh	$/tonne
Off shore wind	$280-$50	.873	$263
Solar	$245-$50	.873	$223
CCGT	$80-$50	.502	$60
Solar vs CT	$245-$146	.53	$187
Solar vs CCGT	$245-$80	.371	$445

These numbers are all based on the assumption that coal-fired generation is being displaced.  While this is arguably the case for wind, which tends to produce more during off-peak periods, it may not be the case for solar which operates primarily during peak periods when the sun is shining.  As a result it is more likely to displace less efficient natural gas fired generation,  

However you look at it, gas-fired combined cycle generation is a less costly resource and a more cost-effective way to reduce GHG emissions than solar or wind.  Given an increase in gas supply availability and continued downward price pressure due to shale gas development, gas-fueled generation could experience growth at the expense of coal and renewable generation.

Getting Started

At long last the time has come to introduce myself to the Blogosphere.  After investigating the required qualifications for blogging and discovering that there aren’t any, I concluded that I am quite qualified, indeed maybe over-qualified to comment on energy issues.  The primary purpose of my blog will be to convey my contrarian perspective, to question conventional wisdom when appropriate, to provide reality checks, to encourage dialogue, and to say what’s on my mind when I think others will or should care.  Most of my posts will be on energy issues - renewable energy, electric transmission, the smart grid, electric vehicles, energy policy, etc.  I will try to avoid pontificating and instead intend to provide a reasoned analysis from a rational perspective.  Any comments, elaborations, suggestions and criticisms are welcome, though I will delete anything that is rude, uncivil or otherwise inappropriate.  My goal is to publish weekly, though not weakly, so let’s see what happens.

Cheers,