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.