Saturday, September 13, 2014

Colorado PUC Gets It Wrong on REC Ownership

On Wednesday, September 10, the Colorado PUC deliberated on docket 13AL-0958E in which the state's major utility, Xcel Energy, filed for a new method to determine the rate at which it would purchase power from small power producers defined in the Public Utilities Regulatory Policies Act (PURPA) as Qualifying Facilities (QFs).  Although net metering isn't mentioned in PURPA per se, it is widely credited with enabling net metering.  But, many utilties have required these small power producers to surrender RECs to the utility as a condition of interconnection and without additional compensation.  Xcel has maintained that net metering is an incentive and, just like rebates and other incentive payments under the Renewable Energy Standard (RES), the utility should be awarded the RECs associated with any QF generation.

In their deliberation on Wednesday, the PUC commissioners in fact awarded to the utility all RECs associated with any QF generation (could be PV, small wind, biomass, etc.) without compensation.  This was wrong for a couple of reasons. First, RECs are instruments created by the RES, not PURPA, and have financial value.  In the RPS world, or even in the voluntary market place, small generators under the RES receive either rebates or other incentive payments from the utility in return for the the RECs associated with renewable generation.  Thus, RECs are a financial asset that may be bought and sold and their sale is how the developer is compensated for the above market costs of building a renewable energy facility.  To take that financial asset from the small power producer simply as a condition of interconnection without compensation is plainly wrong.  Next, while the RES does require that RECs must be transferred to the utility when the developer takes advantage of RES incentive programs, there is no language in either the state RES or federal PURPA statutes that require RECs to be turned over to the utility as a condition of interconnection. Thus, the Commission got it wrong.

To put this in the context of a more concrete example, PURPA is the legislation that requires a utility to purchase power from a QF, such as a small hydro project, at the utility's avoided cost rate.  The Colorado RES is the legislation that created RECs and requires a utility to purchase them when it acquires renewable resources for compliance with the RES.  But, the PUC's recent decision awards the RECs from our hypothetical hydro project to the utility simply because it purchased the power at avoided cost.  But for that, the QF generator could have sold those RECs to any utility with a compliance obligation or even on the open market to people who want to make green claims.  Utility acquisitions made under PURPA do not necessarily imply a purchase made for compliance with the RES. When such a purchase is made at the utility's avoided cost rate, the PUC's decision effectively awards the associated RECs to the utility for free and without compensation to the generator.

Monday, July 28, 2014

DOE Quadrennial Energy Review Meeting on Gas-Electric System Interdependency

Today, the DOE held the 7th meeting in its Quadrennial Energy Review series at Metropolitan State University with the discussion focusing on the interrelationship between natural gas and electric system markets and infrastructure.  Click here for the DOE website.

The discussion of day ahead markets and the fact that electric market operating day begins at midnight while natural gas operating day begins at 9am (central time) may have seemed arcane to some.  The discussion also focused on how firm gas transportation is required to ensure electric system reliability.  This became a big issue last winter when tight natural gas supplies due to cold winter impacted electric generation in the northeast. Given that natural gas is the predominant fuel for home heating, and is playing an increasing role in electrical generation, this becomes a very complex interaction. Think about it this way... when supplies are tight, will the available gas be directed toward heating or electrical generation?  Moreover, how does one use impact the price of the other?  While an electric utility has alternatives to generate electricity, albeit perhaps at a higher price, the consumer with gas heating has no such alternatives to turn to.

The speakers, who mostly came from gas and electric utilities, didn't come to any definitive conclusions but the discussion did highlight the differing perspectives of the two industries.  Apparently, there will be several more meetings in this series in the coming weeks on a variety of energy market topics.

Thursday, April 03, 2014

Sales of Electric Vehicles... and Concerns With Buying the Fuel for Them

If you've been following the papers and some parts of the blogosphere, you're likely familiar with the difficulty that Tesla is having in implementing its direct to consumer sales model.  Those of you on LinkedIn may want to visit a discussion a few of us have been having in the Colorado Renewable Energy Network user group on this topic here.  

I don't intend for this post to debate the pros and cons of electric vehicles aside from one particular concern that I've always had.  No, it isn't the range anxiety, or the time it takes to recharge batteries, or even the cost of the batteries.  My biggest concern is the supplier of the fuel.

In my opinion, electric utilities -- and especially investor owned electric utilities -- already have too much power.  Do we really want to extend their hegemony into the transportation sector too?  Do you want your ability to get to work to now depend on that same monopoly electric utility whose rates constantly escalate and are totally inelastic?  You might say it is a catch 22 between Big Oil and Big Monopoly Electric Utility, but gasoline prices have at least been shown to be somewhat responsive to supply and demand and there is at least some competition in the marketplace.  In most states, however, the price you pay for electricity is established in a rate case that is decided by a public utilities commission or similar agency.  In my experience that is less comforting than letting supply and demand regulate the price of fuel. 

I love the idea of electric vehicles although I am less optimistic than many advocates about their market potential in the near term.  But frankly, my biggest concern is being held hostage by that monopoly fuel provider. What do you think?

Thursday, November 14, 2013

Community Votes on Oil & Gas Fracking Bans

On election day, voters in four Colorado cities – Boulder, Lafayette, Fort Collins, and Broomfield – weighed in on whether or not to allow hydraulic fracturing in their communities.  Measures to ban “fracking” passed easily in the first three while the Broomfield proposition fell short by only a few votes and appears headed for a recount.  As is well known by now, the state regards the regulation of drilling activities as its sole domain and has filed suit over an earlier fracking restriction in Longmont.

It has been well documented that the state and nation as a whole have benefitted immensely from new oil and gas extraction technologies.  The U.S. is now the world’s largest producer of natural gas and, thanks to new production in shale oil and shale gas, is on a path to become a net energy exporter in a few short years – something that would have been unthinkable not long ago.  Moreover, reductions in greenhouse gas emissions from the electrical power sector are the result of the increase in natural gas fired power generation – a direct result of the decrease in price that has accompanied the increased supply due to fracking (the impact of renewables in achieving this reduction, in spite of receiving a disproportionate amount of press, has been negligible in this regard).  So, in spite of the economic and environmental benefits of hydraulic fracturing and horizontal drilling, why did these communities vote to ban them? 

First, there remains a widespread misunderstanding of the environmental concerns associated with hydraulic fracturing.  Fracking occurs thousands of feet below the surface, well below any source of potable water in the country.  And, in spite of some alarmist propaganda, there have been no demonstrable cases of fracking at depth contaminating ground water supplies.  But, with that said, there have been problems, virtually all of which emanate from poor well completions and other surface or near surface drilling contamination.  While these are not an issue with hydraulic fracturing per se (i.e. they could occur with conventional production as well) they are legitimate concerns.  To some extent, the industry is its own worst enemy, whether it is its own failure to adequately take preventive measures against spills or specious claims about the need for trade secret protection for the constituents of frac fluids.

There are some 50,000 oil and gas wells in Colorado with approximately 2,000 new wells drilled each year.  A check of the COGCC incident reporting database reveals that thus far in 2013, there were just over 100 spills that impacted surface or ground water, with about a quarter of those a result of the September floods.  Most others appear not related to drilling and completion activity but resulted from mechanical failures in collection and distribution systems.  Even though that incident rate is only a few percent, you would probably not get on an airplane if the airline industry’s incident rate was that high.  So, perhaps there is something to learn from the exemplary safety record of the airline industry and the transparency afforded by the Airline Safety Reporting System (ASRS) which allows everyone to share and learn from critical incidents that are voluntarily reported by pilots.  FYI, the same has been suggested for the medical community as well.

It is a fair question to ask why local communities should not have the same right to regulate this type of industrial activity within their borders as they do in regulating building permits, construction, transmission lines, or other industrial activities?  But, perhaps they should consider establishing systems to evaluate drilling activity on a well by well basis rather than enact outright bans.  It strikes me that the referenda on hydraulic fracturing are as much a statement on the state’s oversight of drilling as on concerns with fracking itself.  In other words, do the residents of these communities trust the state and its cognizant regulatory authority, the Colorado Oil and Gas Conservation Commission (COGCC), to protect their interests?  The answer, it seems, may be no. 

I have written in the past about the inconsistency in energy development regulation in Colorado noting that, while the state asserts primacy in the regulation of oil and gas drilling, it remains strangely disinterested in permitting electric generating facilities, be they renewable energy related or otherwise.  For instance, I would venture to say that most citizens are entirely unaware that neither the Public Utilities Commission nor the Colorado Energy Office requires even the most minimal registration of, or could provide data on, all of the electrical generating facilities in the state, the principal exception being the Department of Public Health and Environment which issues air quality permits for them.  Drillers, at least, must file a permit application for each well they seek to drill. 

The bottom line is that I would be no more in favor of having a drilling rig 500 feet from my back door than I am having a 400-foot wind turbine there.  And, before critics decry this as NIMBYism at its worst, consider that both drilling and renewable energy facilities represent industrial development that is not wholly compatible with residential neighborhoods.  The important point is not that these types of energy development do not belong anywhere, but rather that they do not belong everywhere.  And, until the supply of energy (be it liquid fuels or electricity) becomes so critically short, there is no reason to find that no land – be it residential or wilderness – should not be off limits.

Yes, the state and the oil and gas industry need to get their acts together and do a better job of understanding and responding to the legitimate concerns of the public.  Perhaps a reporting system analogous to the ASRS mentioned above would help.  Local communities that seek to ban hydraulic fracturing entirely, on the other hand, need to consider more flexible regulatory schemas that can be applied with more precision than a sledge hammer.  The nation, the economy, and the environment have benefitted from unconventional oil and gas development and we need to figure out how to keep this train rolling.

Tuesday, October 29, 2013

Renewable Energy Reality Check

Ordinarily, I don't devote too much space here to repost other writers' columns but I recently came across the One in a Billion blog by Schalk Cloete, a South African doctoral candidate currently studying in Norway.  He recently posted to his blog a column entitled the Renewable Energy Reality Check which I recommend to you. The theme is precisely as it sounds, that is, as a practical matter there is only so much we will be able to do with renewables to combat climate change. Cloete's column has also been reviewed by the Pittsburgh Tribune-Review which can be found here. Of course, there are others who contend that his argument lacks vision. To that I would caution that there is a fine line between vision and hallucination. As a pragmatic renewable energy professional, I find his thoughts worthy of consideration.  


Saturday, October 12, 2013

Colorado's SB-252 Advisory Committee Falls Flat

Upon signing controversial Senate Bill 13-252 which increased the Renewable Energy Standard for Colorado rural electric cooperatives, Governor John Hickenlooper issued an executive order creating an advisory committee to “advise the Director of the Colorado Energy Office (CEO) on the effectiveness of SB13-252.” Specifically, the committee was charged with three goals:
  1. To advise the Director on the feasibility of achieving the twenty percent renewable energy standard by the year 2020, as required by SB13-252;
  2. To advise the Director on administrative and legal considerations related to the two percent consumer rate cap and the impact the rate cap will have on the ability for impacted utilities to comply with the twenty percent renewable energy standard; and
  3. To advise the Director on related legislation for the 2014 session.
Unfortunately, for the reasons I will describe, this was a fool’s errand from the start. The advisory committee was composed of twelve voting and three ex-officio, non-voting members. But, most members of the committee were so poorly versed in the mechanics of Colorado’s renewable energy standard as to render them incapable of informed participation, a situation exacerbated by the CEO’s hiring of a facilitator equally unknowledgeable about any aspect of the RES.



From July through September, the committee met three times in open session. Under pressure from the facilitator, the committee decided that only those recommendations on which it would achieve consensus would be passed on to the CEO. Actually, there didn’t seem to be consensus on this either but given that no one was in charge, the facilitator simply adopted it. The committee’s (or should we say the facilitator’s) second mistake was that only members of the committee would be allowed to participate in the discussion. This left them struggling with understanding important aspects of RES implementation about which there were known and straight forward answers. One such question concerned how the rate cap and surcharge were being implemented by the investor owned utilities. This led to such uncertainty that on one occasion during the second meeting the committee ultimately agreed to allow an unnamed “observer” (yours truly) to explain to the group how the Renewable Energy Standard Adjustment worked.

On September 30, the committee published its final report. While the report describes discussions that took place concerning the feasibility of meeting the RES within the 2% rate cap and other implementation concerns, it is devoid of any consensus recommendations concerning 2014 clean-up legislation. Rather, the report presents five recommendations that were discussed but which failed to receive unanimous support. Only proposals to allow large hydro and energy efficiency to count toward RES compliance received majority support.

The committee did reach consensus in deciding that achieving the 20% by 2020 standard was feasible, but only insofar as the use of purchased RECs was permitted. Other areas in which the committee did reach agreement were that utilities would be allowed to decide for themselves how they would calculate the rate impact and that the rate cap did, in fact, absolve a utility from compliance. The problems with this should be obvious. An additional concern that was not discussed by the committee is the potential in SB-252 for double counting of RECs, which would go against conventionally accepted compliance practices.

Unfortunately, because the committee was isolated from outside input, it also failed to reach consensus on, or even discuss, some common sense changes that would facilitate coop compliance and ameliorate some of the cost impacts. So, I’ll present three of my recommendations which would benefit the distribution coops:

1. Permit thermal RECs to be used for at least 25% of RES compliance. Not only would solar thermal and geothermal heat pump systems facilitate RES compliance, but their inclusion in the list of eligible resources for coops would provide a source of clean energy while also increasing the load factor for the utilities.

2. Rescinding the 1.25 in-state multiplier for Colorado renewable energy systems essentially acknowledged legal concerns that it violated the dormant commerce clause of the U.S. Constitution. But, there would likely be no prohibition against requiring that energy used for compliance be delivered into Colorado (or perhaps even the respective utilities’ service territories). Given that the Colorado grid is, for the most part, an island system, this would provide an alternative way of ensuring that the economic benefits of increasing renewable energy development remain in Colorado. 

3. Focus on increasing hydro power from existing impoundments which would provide a source of clean energy without the environmental impact of building new dams.

These are just three modifications to the RES for coops that would facilitate compliance while making the standard more palatable to Colorado's rural electric utilities. There are ways for coop RES compliance to benefit rural Colorado, but SB-252 was rushed through the legislature without sufficient discussion to enable a complete exploration of the possibilities.

Monday, May 06, 2013

Local Sourcing of Renewables – Desirable? Legal? Inconsistent?

Colorado’s Senate Bill 13-252, which passed through the General Assembly strictly on a partly line vote and which will presumably be signed into law by Governor Hickenlooper, accomplishes three principal objectives:
  1. It expands the renewable energy obligation of the state’s rural electric cooperatives and their wholesale provider, Tri-State G&T; 
  2. Adds electrical generation fueled by captured coal mine methane and syngas from the pyrolysis of municipal solid waste to the eligible energy resources for compliance with the RES; and
  3. Removes the in-state multiplier for compliance with the RES. 
In a column a few weeks ago (click here), I spoke about this bill when it was first introduced and how it was being shepherded through the legislature. One of my principal concerns was that it perpetuates the nonsensical, opaque, retail rate impact calculation in the Colorado RES that has been circumvented at every opportunity by Colorado’s two investor owned utilities with the complicity of legislators and regulators. Though this retail rate mythology persists, I am less concerned about the co-ops abusing it at the expense of their ratepayers than has been done by the IOUs. 

Today I would like to focus on the in-state multipliers which grant a preference to Colorado-based projects over those from out of state. The rationale for eliminating the in-state preference was an acknowledgment that it would likely be found to be an unconstitutional violation of the dormant commerce clause of the U.S. Constitution (Article I which expressly grants to Congress the power to regulate commerce among the states). OK, fair enough, though there are probably ways around that prohibition such as requiring that the project actually deliver energy into Colorado’s grid in order to be eligible for the RES. 

But today, out of Ontario, Canada comes word that the World Trade Organization has ruled against the province’s local content requirements for receipt of incentives paid to producers of renewable energy (click here). While not strictly the same as the in-state preference under Colorado’s RES, the parallels are obvious. Moreover, recall that there has been criticism of wind production tax credits that have been claimed by developers (domestic and foreign) because of the high foreign content of wind turbine generators (especially the generators and gear boxes). Hence, at a national level we find local preferences to be illegal and at an international level we now find local sourcing requirements to be equally problematic. So much for the argument about the economic development benefits of state renewable standards – they may exist but only if the lower transportation costs of local sourcing outweigh the lower costs of foreign produced goods. 

On the other hand, out in Nevada, the legislature is considering a bill to close certain loopholes in Nevada’s renewable standard – coincidentally, also Senate Bill 252 (see the report in the Las Vegas Sun). This bill would ratchet down the amount of energy efficiency credits that can be used toward RPS compliance. According to Nevada’s Governor, the law should not allow the utility “…to meet the portfolio standard by handing out energy-efficient light bulbs at Home Depot.” Seems reasonable. Ironically, Colorado’s Senate Bill 13-272, which would have required that 30 percent of gas-utility DSM funds be dedicated toward more substantive technologies such as solar thermal and ground source heat pumps was killed in committee (see my post on this topic here). Hence, our DSM programs remain focused on energy-efficient light bulbs handed out at Home Depot… and perhaps Lowes.

Friday, April 19, 2013

Comments on Colorado Senate Bill 272 Encouraging Greater Use of Renewable Thermal Technologies in DSM Programs

On April 18, the Colorado Senate Agricultural, Natural Resources and Energy Committee took up SB13-272 which encourages greater use of renewable thermal technologies in utility DSM programs.  I have been advocating such treatment, especially with respect to ground source heat pumps, for several years.  The hearing room was packed with both proponents and opponents and, unfortunately, time constraints did not allow me to testify in favor of the bill.  Below are the prepared remarks that I would have delivered if given the opportunity.



Comments on SB13-272

Richard P. Mignogna, Ph.D., P.E.

Madam Chairperson and members of the committee, thank you for this opportunity to testify in favor of SB13-272.  I am presently the principal in a small consulting firm, Renewable & Alternative Energy Management, LLC in Golden.  Prior to founding my business, I served for more than 6 years on the Staff of the Colorado Public Utilities Commission as a Professional Engineer and Senior Authority on Renewable Energy.  I was, essentially, the fiscal note attached to the legislation implementing Amendment 37.  I am testifying before you today not on behalf of any trade, industry, or advocacy group, but only as an independent, knowledgeable individual to help you evaluate this proposed legislation and act in the public interest.

While at the PUC, I spoke on numerous occasions about the potential for ground source heat pumps, in particular as part of DSM programs.  Hence, it is encouraging to see some of those concepts coming to fruition in this bill.  It has not been a surprise to me that what are termed highly energy efficient renewable thermal technologies have been underrepresented in utility DSM & energy efficiency programs.  Today, you may hear about the low price of natural gas as a contributing factor, but this was true even when natural gas prices were three times what they are now. 

The reasons for this are complex and have more to do with the difficulty in evaluating the benefit/cost ratio of renewable thermal technologies such as solar thermal and ground source (aka geothermal) heat pumps.  On the electric side, determining the energy savings of a new dishwasher or refrigerator, or even CFLs and LEDs is a relatively simple matter.  But, evaluating the energy savings and environmental benefits of thermal technologies used for space conditioning and water heating is more difficult.  No less real, just more difficult.

For example, one must consider whether the installation will be in a heating dominated climate or a cooling dominated climate.  On the heating side, what fuel is being displaced? Propane? Electricity? Natural gas?   On the cooling side, ground source heat pumps displace electricity used to power air conditioning, and naturally the environmental benefits will depend on what fuel would have been used to generate that electricity.  So they perform double duty.  But, while they are extraordinarily efficient, they do have a high first cost and retrofits can be especially challenging, which is why support through DSM programs is especially important.

I understand that the introduced version of SB13-272 has been significantly modified by a strike-below amendment which is presently under consideration.  Nonetheless, I still believe that even the current version of SB13-272 is a positive and welcome step forward in energy efficiency and in fostering consumer applications of renewable thermal energy technologies.

The introduced version of the bill did contain a few notable deficiencies, some of which have been remedied in the current amended version.  The first and most critical was removal of the apparent requirement for cost recovery of a portion of utility DSM expenditures in base rates where they could have been hidden from scrutiny by the ratepayers who are paying for these programs.  This has been one of the principal difficulties with RES funding, much of which is hidden in the Electric Commodity Adjustment (ECA) rider.  Also, present statute §40-3.2-103(2)(c)(I), created by HB07-1037, specifically anticipates cost recovery for DSM without the need to file a rate case, hence the present DSMCA.  With that said, current statute §40-3.2-103(2)(c)(II) and PUC rules already provide utilities with an option to file for base rate recovery of DSM expenditures, so it is not clear that this provision was needed in this bill.

Next, the cap on DSM expenditures of 4 percent of revenues is probably excessive.  Consider that the RESA for the RES is presently set at only 2 percent.  Current gas DSM rules require expenditures of the greater of 2 percent of base rate revenues or ½ percent of total revenues.

A useful provision in the introduced bill, which has been stricken in the amended version, called for utilities to devote 30 percent of their DSM expenditures to renewable thermal energy technologies such as ground source heat pumps and solar thermal systems.  Replacing the 30 percent provision is language that merely instructs the PUC to “give [its] fullest consideration to DSM plans that incorporate a diversity of DSM measures.” The deletion is unfortunate because I don’t believe that the remaining provisions of the bill (i.e., replacing the total resource cost test with a utility resource cost test) will provide sufficient support for these technologies to move the needle. 

The only problem with the 30 percent clause in the original bill was that it called for the PUC to direct utilities to “allocate at least thirty percent of [their] DSM program funding to the development of renewable thermal technologies.” This should merely have been reworded to deployment of renewable thermal technologies since we’re not talking about an R&D program but incentives to encourage consumers to adopt these technologies.  With present DSM programs, ratepayers are already making a substantial investment in energy efficiency.  This bill is needed to help direct that investment more effectively.

Both the introduced and amended versions of the bill instruct the PUC to direct such expenditures by 01 July 2013, but they do not require a rule making identifying the eligible technologies until 30 September 2013.  In my experience, the rule making needs to come first.

With these few, simple fixes, I believe that SB13-272 will be worthy of your support and I encourage its adoption.

Wednesday, April 10, 2013

A Controversial Bill to Expand Colorado's Renewable Energy Standard

An editorial in the 10 April 2013 issue of The Denver Post discusses a proposal recently introduced in the Colorado Senate to extend and expand Colorado's Renewable Energy Standard.  You can read the Post's editorial here.

Those who are interested can track the progress of Senate Bill 13-252 on the Colorado General Assembly website.  In expressing its concern with this bill, the Post states "A 2007 law requires the co-ops and their utility supplier, Tri-State Generation and Transmission Association, to meet a 10 percent renewable standard by 2020."  This is only partly true.  Co-ops are held to a 10-percent by 2020 standard in the RES, but Tri-State G&T, the wholesale supplier to 18 of them, has no compliance obligation at all.  SB13-252 would put Tri-State under a 25-percent standard.

While The Post argues that the legislature may be moving too fast on this bill -- and they may be right -- we have long held that it is fundamentally inequitable for approximately half the state's electricity consumers (the 55 percent who are served by Xcel or Black Hills) to fund the RES obligation while muni and co-op customers enjoy a free pass, or nearly so.  With that said, the 2-percent rate impact limitation crafted in this bill is even more byzantine than the so-called rate impact limitation in the RES for investor-owned utilities (Xcel and Black Hills) which has been treated as merely an inconvenience to be circumvented at every opportunity.  A totally different approach to rate protection and renewable energy funding is called for than what we now have.  If you don't believe that, ask why Xcel's RESA deferred account is tens of millions of dollars in the red -- and upon which you're paying interest.

One of the more beneficial aspects of SB-252, however, is the addition of electricity generation using vented coal mine methane to the list of eligible RES resources.  That provision is clearly worthy of support.

Last, SB-252 also eliminates in-state preferences such as the 1.25 REC multiplier for Colorado-based projects.  This provision, many feel, is an acknowledgement that the suit against Colorado's RES, at least on that point as a violation of the Interstate Commerce Act, is likely to be successful.  But, rather than simply removing the multiplier, the bill's proponents apply the multiplier to all projects regardless of location without limitation, at least through 2014.  That is hard to justify as there are other mechanisms for implementing various preferences that would not violate the Commerce Act.

As I write this piece, SB-252 was recently passed out of the Senate State, Veterans, and Military Affairs Committee (a questionable committee assignment) and on to the Senate floor.  It will be interesting to see what happens to it from there.  



Saturday, September 29, 2012

Solar Doing Good

The other day I discovered that a team from Oakland, California based GRID Alternatives was in Colorado erecting solar PV systems on a dozen Habitat for Humanity homes in Lakewood, Colorado. So, I contacted Stan Greschner, director of GRID Alternatives’ Single-family Affordable Solar Homes (SASH) program to learn more. 

The GRID Alternatives SASH program began as part of the California Solar Initiative and provides low-cost (and in some cases no cost) PV systems to qualifying low income home owners. But there is more to it than that. GRID also leverages the efforts of numerous volunteers from local businesses, trade schools, and elsewhere in the community who learn about solar and gain skills in erecting PV systems. On the day I visited, Stan told me that they had about 30 workers on site each day, most of whom had never before installed a PV system. 

Stan Greschner with volunteers preparing to install a PV
system on a Habitat for Humanity home in Lakewood, Colorado.
A couple of years ago when I led the effort to develop the rules for Colorado Solar Gardens, Stan came out to help us think through how to incorporate a set aside for low income participants in that program. What came out of that was a requirement that 5% of solar garden capacity must be reserved for low income subscribers. At the time, we spoke of GRID’s hope to expand its program outside of California. With the Habitat homes in Lakewood, Colorado has the first GRID Alternatives project outside of California. I’m told that GRID plans to expand its program in Colorado and open a local office here. 

One of the completed systems at GRID Alternatives'
Lakewood, Colorado project.
What I find most encouraging about this program is that it provides utility assistance to those who need it the most while also training the volunteers who install the systems. And, ratepayer contributions into the renewable energy fund are put to good use… truly a win-win-win for all involved. To learn more about GRID Alternatives and the work they do, check out their website at www.gridalternatives.org.

Thursday, September 06, 2012

Fracking Wind Energy and the Production Tax Credit


OK, now that I’ve got your attention… you can’t possibly have a heartbeat and not be aware of ongoing disputes concerning two important energy sources: the expiring Production Tax Credit (PTC) for wind energy and concerns over natural gas well hydraulic fracturing or fracking.  Aside from the fact that both of these issues have become highly politicized, what may be less obvious to many folks is just how closely related these two issues really are.
 
Wind energy proponents argue that without an extension of the PTC (which presently provides a tax credit of $22 per MWh produced for the first 10 years of a project’s life) new wind projects will come to a halt and jobs will be lost.  Hold that thought for a moment but reserve judgment.  On the other hand, the fracking discussion is dominated by environmental concerns with drilling and, in particular, how close drilling should be permitted to residential communities.  Back in June, I penned a guest commentary in The Denver Post concerning the apparent inconsistency in how these two energy sources were treated from a regulatory standpoint (click here for that column).  To wit, the state appears totally disinterested in the proximity of one type of industrial activity (wind) to your back door while claiming primacy in regulating the other.

What is getting lost in this conversation is the fact that the development of wind energy is dependent more on the price of natural gas than on the PTC.  When utilities, such as Xcel, make the case for a new wind energy development, it is based on a comparison to an equivalent amount of electrical generation from gas-fired generators.  While the PTC helps tilt that comparison toward wind, low natural gas prices shift the balance back in favor of gas generators.  And, what is keeping natural gas prices so low?  The development of previously unrecoverable shale gas resources using horizontal drilling and, yes, fracking.
 
On the one hand stands a more than 20-year-old energy industry (wind) that claims that it still needs a public subsidy “head start” to compete, and on the other we have an even older energy resource that owes its resurgence to technological advance.  Wind is among the least dense energy sources that we have, contributes to energy sprawl covering thousands of acres, and typically produces the most when demand is the least (i.e., the middle of the night).  Natural gas generators, in contrast, are relatively compact, flexible, and produce when demand is high.  The drilling, however, leads to its own kind of sprawl.  Importantly, as evidenced in recent Energy Information Agency reports, it is the increase in natural gas-fired generation that is primarily responsible for recent reductions in CO2 emissions from electrical generation.

Jobs are at stake with both energy sources so that argument is weak.  At what point in time does wind energy get weaned off the public subsidy – whether it be production tax credits or higher ratepayer costs that result from the Renewable Energy Standard?  Discussing the pros and cons of solar would consume more electrons than can be allotted to this post, so I won’t even begin to get into that, other than to say that there are both pros and cons there too.  The Administration’s all-of-the-above strategy is nonsense.  What is needed is an all-that-is-smart approach.
 
Environmental concerns with fracking are not totally without merit.  However, they emanate more from poor well completions and near surface drilling contamination than from what occurs deep underground.  And, I don’t believe that arguments calling for greater setbacks of drilling activity from residential communities are misplaced either.  Hence, Governor Hickenlooper’s recent suggestion that additional changes to the oil and gas drilling rules may be in order is well taken.  On the wind energy side, it is well past time that this industry got its costs in line so that it can compete head to head with other energy sources.  Cutting off the PTC cold turkey may not be in the public interest, but phasing it out over a few years may well be.  Wind needs to focus more on real engineering and less on financial engineering.  Both sources of energy will be important to the future development of sustainable clean energy generation.

Saturday, June 16, 2012

24 Heures Du Mans -- Now that's an auto race!

For this post, I thought we'd take a bit of a departure from our usual energy topics -- sort of.  This weekend will be the 80th running of the 24 Hours of Le Mans -- one of the world's most grueling auto races.  So, how does this fit in with our theme of emerging technologies?  Simple... the race track has long been where new technologies are developed and refined long before they make it to the consumer showroom.  Check out the pic below from the NY Times for two of the most high tech vehicles ever built.

Audi R18 E-Tron Quattro leading Toyota TS030 at Le Mans test day. NY Times
One of the things that makes Le Mans so intriguing is the LMP1 class which stands for Le Mans Prototype 1.  This is the class where the latest technologies are put to the test.  For instance, both of the vehicles in the picture above employ Kinetic Energy Recovery Systems (KERS).  "What is that?" you ask.  Think of it as a super regenerative breaking system that is common on current electric vehicles and hybrids.  While the regenerative breaking system on your Nissan Leaf, for instance, simply helps recharge the battery, in a KERS the energy recovered on braking going into a turn is then immediately used to provide a horsepower boost coming out of the turn.  The two vehicles above do this differently.  The Audi R18 E-Tron (a diesel vehicle by the way) employs a rapid response flywheel while the Toyota utilizes a capacitor to store the energy.  Very cool stuff.

And, in case you're wondering how a diesel could possibly win an auto race, the Audi shown above is no ordinary diesel -- it has won this race 10 of the last 12 years.  Le Mans will also feature hybrid vehicles and for 2013 there is also talk of a completely fossil free hydrogen-electric hybrid.  If you want to learn more about this years race, check out a recent article in the NY Times or go to the Le Mans website to learn about the different classes of vehicles.   

The race wraps up at 7:00am Sunday, 17 June (MDT).  If you can't find it on your TV, check out the live webcast here.

Saturday, May 26, 2012

Recognition for Ground Source Heat Pumps -- the little g in Geothermal

Over the years, proponents of some forms of geothermal energy have suffered from a bit of an identity crisis. There is, of course, Big G which generally refers to hydrogeothermal resources of the type that create geothermal electrical generation common to northern California, Nevada, Indonesia, etc. and shown below in the new Hudson Ranch I system that recently went online in the Salton Sea of California.
Big G also commonly refers to geothermal resources used for direct use as in hot springs resorts and the district heating system in Pagosa Springs, Colorado.
Then there is "little g" which refers variously to geothermal heat pumps (GHP), geoexchange, or, more appropriately, ground source heat pumps (GSHP) -- a fundamentally different energy resource and technology than Big G. It doesn't help that both Big G and little g, and which both suffer from a bit of a Rodney Dangerfield complex, are often discussed at the same conferences which only further confuses the two. Rather than a resource for electrical generation or direct use heating, ground source is better looked at as an energy efficiency device that can provide both heating and cooling for space conditioning (I won't go into the details here. Interested readers might want to start out with the Wikipedia entry). 

The basic problem with ground source is the high first cost of installing the loop field. While improving technology has increased the efficiency and cost effectiveness of the heat pump component of the system, there has been little improvement in the cost of installing the loop (see the excellent article by Tom Konrad in Forbes here). Thus, for residential systems in particular, GSHP remains at a competitive disadvantage -- especially in light of low natural gas prices. 

I have long argued that ground source deserves more recognition in utility demand side management/energy efficiency programs, most of which focus on weatherization programs (good) and nothing more sophisticated than rebates for kitchen appliances and compact fluorescent light bulbs (questionable). Some states have enhanced their renewable energy standards with new thermal energy standards. These have tended to focus more on solar hot water heating and, occasionally, biomass... still not much recognition for the only technology that provides both heating and cooling. 

During this legislative session in Colorado, a group convened to attempt to foster greater recognition for ground source in a thermal energy standard that was being discussed. Unfortunately, the single paragraph that discussed geothermal or ground source in what became Senate Bill 12-180 was lost in what morphed essentially into a biomass/forest conservation bill. That the bill was introduced late in the session and was tagged with a large fiscal note did not bode well for its prospects and it was soon killed in committee. That was probably just as well since the bill was a mess and the best it would have done would have been to create a thermal energy working group. In the present economic environment, and with little support for new incentive programs, I suspect that ground source is going to have to continue to rely on technological advance and new financial innovations (similar to the PPAs that have fostered greater PV adoption) to reduce the first cost to consumers so that it can compete with more established space conditioning technologies.

Saturday, May 19, 2012

World's Largest Concentrating PV System Goes Hot in Colorado!

Fans of utility-scale solar PV are likely aware of the world’s largest highly concentrating PV (HCPV) system that has been under construction in the heart of Colorado’s San Luis Valley. On May 10, Cogentrix Energy, LLC (a unit of Goldman Sachs) announced that it has achieved commercial operation at its 30MW HCPV project which will provide solar energy to Public Service Company of Colorado (PSCo) for compliance with the utility’s wholesale DG obligation under Colorado’s Renewable Energy Standard. The Amonix MegaModule® assemblies that form the heart of this system rely on Fresnel lenses to concentrate solar irradiation 500 suns onto triple junction solar cells originally developed by SpectroLab (a Boeing company) as part of the US space program. Looking like something out of the movie Transformers, the project consists of over 500 60kW (nominal) dual axis trackers on approximately 225 acres approximately 14 miles NW of the southern Colorado town of Alamosa (click here for a Google map). 

Truly an impressive facility, this project was bid into the 2009 All Source Solicitation conducted as part of PSCo’s 2007 Electric Resource Plan (Colorado PUC docket 07A-447E). Electricity from the plant, estimated at approximately 75,000 MWh for the first full year of operation, is provided to PSCo under a 20-year PPA. Financing for the approximately $145 million project was facilitated by a $90.6 million loan guarantee from the US Department of Energy proving that not all DOE-backed funding necessarily had to result in Solyndra-like failures (in fact, there is a fundamental difference between providing a loan guarantee for an energy development project such as this and a manufacturing facility such as Solyndra). The one downside, albeit a significant one, is that the Colorado PUC exempted this project along with another 30MW project in the San Luis Valley developed by Iberdrola Renewables from the 2% rate cap in Colorado's renewable standard. As I’ve pointed out previously, compliance with Colorado’s RES has been achieved, and even exceeded, but at a cost far greater than the 2% rate cap stipulated in the statute. 

Back in October 2011, I had the opportunity to tour the facility with Cogentrix VP Jef Freeman while it was still under construction. Below are a handful of the pictures I took at that time.


Approaching the plant from the southeast, it is difficult to get a true appreciation for the scale of the facility.


Looking closer, it isn't clear if this is a solar facility or a spaceport!


Loading the Amonix MegaModule panel assemblies onto the pedestals.

Look close and you might see the workers attaching the panel assembly to the pedestal from below.

To get a feel for the scale, check out the pickup truck in comparison to the trackers.  The Solectria inverter on each tracker can be seen in the foreground.
When not tracking the sun, or stored due to high winds, the panels will remain horizontal as shown here.


All photos Copyright Richard Mignogna, 2011.













Wednesday, April 11, 2012

Discrepancies in Colorado Energy Land Use Policies


There is a discrepancy playing out in Colorado’s energy landscape and energy regulatory policy that may be poorly understood by officials and consumers alike.  It has to do with local control versus establishing statewide standards for siting energy facilities of all types.  

This legislative session has seen the introduction of a number of initiatives to enhance local control over the siting of oil and gas drilling activity largely intended to allow local jurisdictions to restrict the proximity of drilling activity to residential developments. These initiatives were opposed by, among others, the Hickenlooper administration and its cognizant regulatory agency, the Colorado Oil and Gas Conservation Commission (COGCC).  The argument essentially put forth by COGCC was that there needs to be uniform standards for siting drilling activity and that it is the agency best qualified to monitor and regulate the industry and to establish and enforce such standards.  As a hoped-for solution to the dispute between factions seeking local control versus statewide control, the administration has convened a task force and charged it with an ambitious agenda of reconciling local concerns with state agency control in only a few weeks time.

In contrast, consider the regulatory regime governing the siting of electrical generation facilities.  While the state agency of competent jurisdiction most closely associated with the development of electrical generation facilities is the Colorado Public Utilities Commission (CPUC), with the possible exception of transmission line siting, it wields little influence in the siting of electrical generation facilities be they coal fired, natural gas fired, solar, wind, or otherwise.  Rather, satisfying environmental concerns, economic concerns, building permits, and land use issues for facilities outside of municipalities rests solely in the hands of county commissions through what is known as the 1041 permit process.  One of the areas in which the discrepancy between state control of oil & gas development versus local control of power generation has become most obvious is the siting of wind and solar renewable energy facilities, and one of the cases that has received considerable recent attention is the 1041 permit process for a concentrating solar power facility near the San Luis Valley town of Center in Saguache County.

The Saguache County project, proposed by California solar developer Solar Reserve, posits the development of two concentrating solar electric generation facilities known as “power towers.”  A number of groups expressed environmental, wildlife, view shed, and quality of life concerns with this proposal to construct two 656-foot towers smack in the middle of the Valley on land that is presently dedicated to agricultural use.  In a 2 – 1 decision, the Saguache County commissioners recently approved the Solar Reserve 1041 permit application.  In its decision, the County Commission eschewed the aforementioned concerns in favor of the promised economic impact that the development would have.  If you’re having difficulty envisioning what this project entails, consider that the development would create an industrial facility encompassing approximately six square miles, the central focus of which would be two towers that are only 50 feet short of the tallest building in downtown Denver.  It is difficult to envision how such a project, with the Sand Dunes National Park and Sangre de Cristo Mountains to the east and the San Juan Mountains to the west, fits into the character of what is largely a pristine agricultural area.

A similar issue concerning the state’s abrogation of its siting authority to local officials can be found in the siting of wind turbines.  Here too, the absence of any statewide siting rules is troubling.  Apparently, it is acceptable for state officials to take a hands-off approach to the construction of a massive 400-foot wind turbine with a life expectancy of 20 years or more 300 feet from your back door, leaving the decision to local officials, but only a state agency may weigh in on the drilling of an oil or gas well the same distance away.  This certainly seems inconsistent.  To be fair, COGCC at least maintains a database of all such drilling activity, issues permits, and monitors each well while CPUC in particular, and the state in general, seem strangely disinterested in regulating any aspect of the construction of wind or solar facilities having at least as great an impact.  Moreover, the public would likely find troubling the fact that CPUC does not even maintain a list or require the most minimal registration for any renewable energy generation facility, be it a $400 million wind farm or a $50,000 solar installation. Sadly, attempts at requiring CPUC to maintain such information in the past were met with resistance by public officials, utilities, and developers alike.
  
The concern here is not whether oil and gas development should fall under local or state jurisdiction.  Nor should this be construed as an argument in favor of limiting additional renewable energy development, as some will undoubtedly assume.  What is of concern is that there is a troubling inconsistency in the regulation of different energy sources based, apparently, on little more than political agenda.

Thursday, January 26, 2012

An Insider’s Perspective on Colorado's Renewable Energy Standard – Some Critical Thinking about Colorado's "Successful" RES

As indicated in Mark Jaffe’s article, Power Surge Slows (The Denver Post, January 22, 2012), Colorado’s Renewable Energy Standard (RES) has in many respects been one of the more successful ones in the country. With rare exception, such as California’s 33% by 2020 goal, it is certainly one of the most ambitious. But, there is more to understand before we declare it an unqualified success. Importantly, the slow-down described in the article did not have to occur if only the state’s principal utility, bolstered by lax regulatory oversight, had acquired renewable resources in a more fiscally responsible and sustainable manner.

Among the benefits derived from the RES is that Colorado has attracted a handful of big name manufacturers such as Vestas and General Electric in wind turbine and solar panel manufacturing, respectively. Hopefully their local operations will prosper in spite of a difficult economic climate and tenacious competition from abroad. Colorado also has had, until recently, a thriving small solar installer industry but its success was predicated on too-generous incentives that broke the Ratepayer Bank while the Public Utilities Commission was late in recognizing the severity of the problem. Mark Jaffe’s article noted that Xcel Energy’s renewable fund – known as the Renewable Energy Standard Adjustment (RESA) account – is $51 million in the red and headed for worse before it gets better. What is less well known is that the utility earns its Commission approved rate of return on this deficit – a great deal if you can get it.

Xcel has asserted that it has already met Colorado's 30% RPS clear out to 2028. On the surface, that sounds great. But let’s come back to that RESA deficit. What achieving compliance with the renewable standard a decade early really means is that ratepayers have been on the hook for resources that were not needed for compliance or to serve load. As the PUC Staff warned more than once, Xcel was purchasing “too much, too soon, at too high a cost” and that, especially with regard to the small solar program, this would lead to the same boom and bust that has afflicted myriad other solar incentive programs that over-compensated solar customers. One needn’t have been prescient to predict this outcome. Rather than stage its acquisition of renewable resources commensurate with the ramp-up in the RES, and in so doing take advantage of the rapidly declining cost of renewable energy in the process, Xcel spent future receipts from the renewable fund driving it deep into the hole until the deficit became so severe that even the most ardent supporters of renewable energy had to take notice. It was at that point that Xcel came to the PUC with a drastic plan to cut back on the incentives it was doling out to solar customers. Xcel and its customers were not alone. The same affliction befell the state’s other investor owned utility (IOU), Black Hills Colorado Electric, though at a much smaller scale. The result was inevitable – a boom and bust that did not have to be and one that the Commission’s staff warned about as early as 2007. Moreover, the slow-down described in Mark Jaffe’s article extends to the development of utility scale projects as well as the small solar market. 

Xcel has argued that, while it has exceeded the goals for the renewable energy mandate, it has stayed within the 2% cap established in the enabling legislation for the RES. This misrepresents the true situation due to the convoluted and opaque rate cap formula used in Colorado’s RES which makes it difficult to discern the actual rate impact. Xcel argues that it is only charging an additional 2% on each customer’s bill. That is true, but it does not consider the accrued liability in the hemorrhaging RESA deferred account nor does it include the cost of resources for which the PUC has granted a “waiver” from the rate impact calculation. As demonstrated in numerous PUC Staff analyses, when all of the costs are accounted for, the actual costs of renewable energy penetration in Colorado have far exceeded the 2% rate cap by any reasonable, common sense definition of the term. Unfortunately, the IOUs have been allowed to redefine the plain meaning of 2% in a way that masks the true cost of renewable energy in Colorado. Were this not the case, and had the PUC under the prior administration exercised proper oversight of the regulated utilities' renewable expenditures, the small solar industry in Colorado would not now be decrying the drastic, but necessary, reductions in incentive payments available to their customers. 

A sufficiently skeptical observer might ask why a utility that fought the imposition of the renewable standard so vigorously back in 2004 would later reverse course and spend more than necessary to blow the compliance targets away and brag that it has met its compliance obligation more than a decade early. Many observers believe that it is because the utility figured out how to make money at it! Bear in mind that the utility has invested none of its own money in renewable energy and is promised full recovery of every dime – often plus interest – of consumer funds that it does spend. In my post on the 12th of January, I wrote about the PUC's rejection of Xcel's attempt to profit unconscionably from this behavior (Click here for that column).

The evidence from multiple PUC proceedings is that Xcel has acquired renewable resources (primarily wind energy) that it does not need either to serve load or for RES compliance so that it can profit from the sale of the excess renewable energy credits (RECs) to other utilities. As I wrote in testimony in Xcel’s 2010 Amended Resource Planning proceeding, this provides the utility with a perverse incentive to acquire more RECs than needed, bought and paid for with interest by Colorado ratepayers, allowing the utility to profit on both ends of the transaction.

Not surprisingly, the utility has gone to great lengths to prevent the disclosure of this fact – something that the PUC's own Staff has warned about for several years now. But, the data do not lie. Fortunately, with a new governor and under the leadership of new PUC Chairman Joshua Epel, the Commission is now taking steps to right the ship. But it's a big job and it will take a while to pay down the deficit in the renewable energy accounts. Thus vigilance by an informed public is still needed. 

Unfortunately, balancing the renewable budget now will not mitigate the boom and bust I spoke about earlier or the need to transition to clean energy in a sustainable manner as the utility, in its current resource planning docket, has made it clear that it has very modest needs for additional renewable generation for some time to come. 

So, how do we move forward from here? Clearly we need to restructure some of the details of the RES including, most importantly, the way it is administered. Obviously, the widely discussed tax incentives available to renewable developers, including the soon to expire production tax credit for wind energy, are important, but the individual states have limited ability to influence that. So, here is a short list of things that we may want to consider:
  1. Modify the liberal REC banking rules, i.e. the shelf life of RECs, in the Colorado RES. At the present time, a REC may be used for compliance for as long as five years beyond the year in which it was generated. Restricting the bankability of RECs would more closely tie actual renewable generation to current compliance obligations and discourage making expenditures far in advance of requirements. 
  2. Consider a different mechanism for funding renewable energy development – perhaps a Public Benefits Fund paid into by all utility customers in Colorado with investment in renewable projects flowing back to the areas in approximate proportion to their level of contribution. As all the rest of us must do, set a transparent, firm budget and manage to it. 
  3. Increase the renewable compliance targets for the state’s rural electric coops and municipal utilities (presently only 10% by 2020) to something akin to that for the two investor owned utilities. The obligation for compliance with the renewable standard should be shared equally by all of the residents of Colorado, not just the 55% who are customers of the state’s two IOUs. Furthermore, it seems unfair for the availability of consumer benefits, such as solar incentive payments, under a statewide program such as the renewable energy standard to be solely a function of your address. 
  4. Perhaps the most important change would shift responsibility for administration of the renewable standard away from the utilities and into the hands of a public agency (perhaps the PUC or the Governor’s Energy Office) or a non-profit third party administrator. The state’s investor owned utilities, upon whom the bulk of the obligation for compliance with the renewable standard has fallen, have not shown themselves to be good stewards of the public’s investment in renewable energy. 
There are many people, including me, who would be willing to pay more than 2% to aid the transition to a clean energy infrastructure – if the money is spent responsibly. But, a promise made to the voters to limit the cost impact should be a promise kept. With proper management and guidance, compliance with the RES could have been achieved in a responsible manner and at reasonable cost. Unfortunately, you cannot build a sustainable energy infrastructure on the back of unsustainable economics.

Thursday, January 12, 2012

Consumers go 2-0 in recent decisions at Colorado PUC

Consumers went 2-0 in important decisions at the Colorado PUC this week in cases involving the state's dominant utility, Xcel Energy.  One decision, yesterday's rejection of Xcel's request for interim "rate relief" (right, not really sure who is in need of the relief but that's what they called it) made the papers and the blogosphere this morning.  The other, an equally if not more important decision on Tuesday concerning the utility's request to keep 40% of the proceeds from the trading of what are known at Hybrid RECs (docket 11A-510E), received little if any notice because a) it is far more difficult to understand and b) the impact is less noticeable to consumers.... note, I said less noticeable, not less important.  

So, let's start with the 510E docket.  As I've written about here previously and in testimony before the commission as well as some other public arenas, the PUC has allowed Xcel to acquire "too much, too soon, at too high a cost" with the ultimate impact that the 2% rate impact limitation in the renewable standard statute has been circumvented by the adept use of misdirection, accounting chicanery, and political decision making.  But, why would a utility that fought the imposition of the renewable standard so vigorously then turn around and spend more than necessary to blow the compliance targets away and brag that it has met its compliance obligation more than a decade early? There is no way to fully explain the volumes of PUC Staff analysis and testimony in this small space, but the bottom line answer is that Xcel (aka Public Service Company of Colorado or PSCo) has figured out how to make money at it!  Keep in mind that the utility has invested none of its own money (zero, nada) in renewable energy and is promised full recovery of every dime -- plus interest -- of consumer funds that it does spend.  The unfortunate impact has been that consumers are being saddled with costs in excess of the statutory 2% rate cap.  Another impact that only a few understand is that, as I explained in testimony way back in the 2007 RES Compliance Plan docket, it would and -- and indeed has -- lead to a boom and bust in the Colorado renewable energy market.  

Hence, being flush with more RECs than needed for compliance under any scenario, Xcel saw an opportunity to sell its excess RECs to utilities in California that were having difficulty complying with that state's RPS.  The term "hybrid REC" came about because California, ever hungry for electricity, required that RECs generated outside the state be bundled with energy from another source that could be imported into the state.  In the process, the company has made an obscene profit from the sale of these excess RECs that have been bought and paid for by Colorado consumers with interest.  In return for employing its "skill" in effectuating such transactions, Xcel thought that it should be allowed to retain an astonishing 40% of the proceeds with the remainder being used to buy down the deficit in its renewable accounts (known as the RESA deferred account) so that it could.... you guessed it.... acquire even more RECs at consumer expense for it to sell at a profit using OPM (that's Other People's Money).  Keep in mind that we're talking about margins well into the eight and approaching nine figures here (that's without the decimal point) so this was not exactly pocket change (OK, that's tens and approaching hundreds of millions of dollars in play).  This was about as close to a perpetual motion money making machine as I've ever seen.

The PUC's staff, the Office of Consumer Counsel, large industrial customers and others did recognize that the company should be credited with some finder's fee for identifying these trading opportunities but nowhere near 40%.  They also differed on the mechanism through which the customer share should be returned to ratepayers.  On Tuesday, after volumes of testimony submitted by all sides and aborted settlement negotiations that failed to yield an acceptable outcome, the commission deliberated and made its decision.  Where did they come down?

The ultimate decision awarded Xcel even less than the 20% share proposed by the PUC staff and most of the other intervenors.  The outcome was that Xcel could retain 20% of the first $10 million in margins, 15% of margins greater than $10 million and up to $30 million, and only 10% of margins beyond $30 million -- proof that it doesn't pay to be greedy.  These sharing percentages are to remain in effect through 2014 after which the PUC could reevaluate the situation.  As to the mechanism for returning the customer share, here is where the PUC could have done a better job.  Concerned about the deficit in the RESA deferred account that is well into the tens of millions of dollars (see my RPS rate cap presentation posted elsewhere on this blog), the commission elected to first use the proceeds to pay down the RESA, but I am a bit less concerned about that now that the commission has indicated its intent to keep a closer eye on this.  As is typical we'll have to wait for the final written decision, to be followed by the inevitable RRR (that's application for rehearing, reargument, and reconsideration) before we're fully comfortable with this outcome.  And, unfortunately, none of this completely mitigates the boom and bust I spoke about earlier or the need to transition to clean energy in a sustainable manner as the utility, in its active resource planning docket, has made it clear that it doesn't need any more renewable generation for some time to come.

As for Xcel's application for interim rate relief (docket 11M-951E) that was rejected by the commission on Wednesday, Chairman Epel said it best when he noted that without some showing of adversity, "there is no need for rate relief."  Though their reasons differed, the three commissioners came down on the side of rejecting the interim rate hike.  Commissioner Tarpey noted that the company is already close to its authorized rate of return and Commissioner Baker was the closest to granting the request noting that "regulatory lag could be considered a form of adversity." Fortunately, neither of the other two commissioners bought that argument.  And, while this is encouraging, Xcel still has before the commission its request for a $142 million rate increase (docket 11AL-947E) which has yet to be adjudicated.  All this decision did was prevent the utility from collecting the lion's share of that request prior to a final decision in that case.  Thus, continued vigilance by the public is still necessary.