Monday, November 10, 2014

Electric Vehicle Car Sharing Comes to Colorado

Last Saturday, a new entry in the Colorado car sharing market opened its doors, right here in Golden no less.  eThos Electric Car Share bills itself as the nation’s first all–electric vehicle car sharing service.  I'm not sure it's the first in the nation but first in Colorado will do.  eThos, which opened its doors in a converted service station at the corner of 19th Street and Jackson Street runs much like most other car sharing services, except for its 100% EV fleet.

For those who are not familiar with car sharing, think auto rental but on an hourly basis.  There are two basic types of car sharing services: business-to-consumer (B2C), which provides cars on an hourly or daily basis to business or individual consumers, and peer-to-peer in which an individual provides access to his or her personal vehicle to the renter, much like you might rent a vacation home from an individual owner.   There is one other important distinction to be made between types of car sharing services and that is whether the vehicle must be returned to the point of rental (aka round-trip) or may be dropped off at a designated parking location (aka point-to-point, free floating, or one-way) whereupon it may be rented by another customer.  eThos is a B2C, round-trip operation.




The Denver market has three B2C round-trip car sharing services – eGo CarShare (a nonprofit), Zipcar, and Enterprise CarShare – and one point-to-point service, Car2Go.  Generally, their rates are similar starting at about $5 per hour at the low end and increasing from there, depending on the specific vehicle make and model.  Hourly rates typically include gas, maintenance, and insurance though you can pay more for a waiver to cover the company’s deductible, just like with any car rental.  Depending on the rate plan the customer signs up for, there may also be mileage charges and a membership fee.  The three round trip services have a number of access points throughout Denver and a variety of different vehicles.  Car2Go is unique in that its vehicles may be found parked at meters or other public parking spaces throughout Denver – wherever the prior renter leaves it.  Car2Go apparently is intended to provide transportation only within Denver and has only Smart Cars – those little two-seaters sold by Mercedes Benz.  The location of its 372 vehicle fleet can be found by checking their website or smart phone app.

So, how is eThos different?  As noted, eThos requires that the vehicle be returned to its home base which, for now, is its sole location in Golden.  None of the other car sharing services come out this far from central Denver or Boulder.  But eThos’ main difference is that its fleet consists of only electric vehicles which, at the present time, includes 8 Codas (more on that in a minute) and one Tesla.  Pricing is competitive with the other services at $7 per hour for up to 250 rental hours (for a Coda) down to $5 per hour for over 500 rental hours.  The Tesla rents for three times the hourly rate of the Coda. Would I pay $21 an hour to drive a Tesla?  No. Let me know when you've got an i8 and we can talk about it.

OK, so what’s a Coda?  Coda Automotive was a California based EV manufacturer that had a short, inauspicious life.  The company produced 5-passenger, 4-door EV sedans in 2012 and 2013 before succumbing to bankruptcy in May 2013.  Built on a frame imported from China, the Coda includes a 31 kWh battery pack and a drive train supplied by Colorado’s own UQM Technologies (which coincidentally also started out in Golden as Unique Mobility, Inc. before moving to Longmont).  At the time of its bankruptcy, the company had reportedly delivered only 117 vehicles.  The remaining stock of 50 vehicles and 100 gliders (no powertrain) were purchased by a couple of remarketers and sold at deep discounts from the $38,000 MSRP (you can read more about them on Green Car Reports.  Coda’s restructuring plan calls for it to morph into a provider of grid storage solutions.



eThos apparently acquired a dozen Codas (8 available and 4 awaiting delivery) and the one Tesla which comprise its current fleet.  At the Grand Opening, I went down and took a short test drive in a Coda (I’m not yet cleared to drive the Tesla).  It is a quiet, reasonable vehicle for getting around town though with a range of 100 miles or less and a 6-hour recharging time (Level II), you’re not going too far in it.  So the market appears to be people who have a need for a vehicle to tool around for a half day or so which is pretty much the market for any other car sharing service.  And, since my aging Vehicross seems to be giving me increasing trouble lately, I may need access to a car share so I signed up for an account ($50 membership fee that was waived on opening day plus a $25 DMV license check fee).

I had a chance to speak briefly with the firm’s two principals, founder Tim Prior and Assistant Manager Kathryn Saphire and wish them the best of luck with their new business. I think that Golden is going to be a challenging market for them, one that will be easier to access if they offer to pick up customers and bring them home after the rental (hint). On the other hand, Golden is a pretty techy community so hopefully it works as a launch point. Alas, it isn’t clear how they’re going to expand or replenish their fleet… unless there are more discounted Codas sitting around out there to be had.  If so, they need to find a red one.

Friday, November 07, 2014

A Message to California About Collecting Solar System Data

California, you will soon be deciding an interesting debate about who, if anyone, should be collecting data about the state’s distributed generation installations.  Under the California Solar Initiative (CSI), information about all of the systems that took advantage of the CSI incentives has been collected and published on the California Solar Statistics website.  One would think that such transparency that allows an agency and other interested parties to track the success of a program funded with public money would be a no-brainer.  Apparently, it isn’t.

California Public Utilities Commission, you will soon be issuing a final ruling on minimum reporting requirements that, with the phase out of the CSI, would now fall to the utilities.  This was reported recently in Solar Industry Magazine available here.  According to the article, unsurprisingly, certain large developers and the utilities oppose these eminently reasonable reporting requirements citing such specious arguments as the cost of providing this data ($7 to $22 on systems costing tens or hundreds of thousands of dollars).

For years, California and CSI you got this right.  As noted in Solar Industry Magazine The information is supposed to let manufacturers, contractors and investors know which equipment is being installed and where, provide academics and journalists with industry information, and help utilities understand more about their distributed generation fleet.”  This debate brings to mind a similar one that existed in Colorado back in 2006 concerning the collection of information on that state’s solar incentive program.
 
At that time, a Colorado PUC staffer was assigned to assess a utility application to implement a forward-looking tariff that would fund the nascent solar incentive program under Colorado’s new Renewable Energy Standard (RES).  That new tariff came to be known as the Renewable Energy Standard Adjustment (RESA) and it now collects a bit over $50 million a year in customer money from that one utility and a lesser amount from a second, smaller utility (the fact that the utilities have been allowed to be the administrators of those accounts raises other concerns but that is a different discussion).  At the time, the requested tariff of 1% of customer billings was projected to raise approximately $20 million per year.  The PUC staffer was charged with recommending to the Commission whether the tariff should be allowed to go into effect unopposed or should be suspended and set for hearing.

Ever the dutiful public servant, and having not inconsiderable experience in major industrial project management in the private sector, this staff member requested from the utility a pro forma budget indicating how the funds were to be spent.  He was told there was none.  The rest of the conversation was brief:

PUC Staff: Then why are you asking for $20 million?

Utility: Because we can.

The tariff was suspended and set for hearing initiating Colorado PUC docket 06S-016E.

Through subsequent negotiations, the initial RESA tariff would be set at 0.6% of customer bills on the condition that the utility provide the PUC with a monthly report from its database that included much the same data that CSI has been collecting.  That too took a strange twist.  That conversation went something like this:

PUC Staff: We’re interested in tracking the growth of the program and how the incentives will contribute to the development of the solar industry in Colorado.  So, we would like a monthly report from the solar registration database.

Utility: What database?  We’re not going to have any database.

PUC Staff:  Well, how are customers and installers going to apply for the rebates?

Utility: They’ll submit an application with all of the interconnection data and rebate information on it.  But, there won’t be a database.

PUC Staff:  Really?

Utility: If you want that information, we’ll send you paper copies of all of the applications each month and you can create your own database.

PUC Staff:  Oh, well.  OK.

And so for the next 6 months the utility dutifully submitted seven copies (as required by PUC rules for all paper submittals) of all of the solar rebate applications which an intern working for the staffer gleefully compiled into a database of system level data using Microsoft Excel.  That is, until the utility representative’s successor came back to the PUC staffer and said:

Utility: Look, we’re really tired of copying all of these applications and hauling them over every month.  How about we just send you a copy of the database on CD each month?

PUC Staff:  You mean the database that you don’t have?

Utility: Yeah, that one.

And so, the PUC staffer ultimately used this data to report to the public on the success of the solar rebate program, where the incentive payments were going county by county, how system costs were falling, the level of economic activity generated by the program, and many other statistics that the public and policy makers would (or should) want to about how hundreds of millions of dollars in support for the renewable program was being spent.

The first publicly issued report of this data showing four years’ worth of data on solar installations in the state was welcomed by many and was especially of interest to the installer community.  Curiously, the report was not welcomed by certain PUC bureaucrats and the utilities who together sought to quash the report because they felt that it reflected negatively on their administration of the solar program. It didn’t but the report did contain some policy recommendations to manage the program more effectively in the public interest.  The agency even went so far as to deny an open records act request by the industry trade association seeking a copy of the report.

Ultimately, the report became the focus of a Whistleblower complaint and was released by a state personnel department administrative law judge who soundly rejected agency and utility arguments for a protective order that would bar disclosure of the information contained in the report.  Sadly, by the time all of this had occurred, much of the information contained in the report had become stale. Today, the arguments in many states are no longer over solar subsidies per se, but whether net metering and distributed generation itself provides a subsidy that disadvantages a utility and the general body of ratepayers.

The end of this story is that docket 06S-016E is still open and utilities still contribute monthly reports of their collections and expenditures of RESA funds. However, neither the utilities nor the agency appear interested in a comprehensive analysis of the systems installed using those funds and the policy implications thereof.  

The moral of this story for you California is that you’ve been doing the right thing in the collection and publication of this system level data all along and should continue to do so to foster transparency in the administration of programs in the public interest.

Friday, October 10, 2014

Analyzing Trends in Solar Cell Efficiencies for Fun and Profit

In Future Solar Cost Reductions Hinge on Raising Solar Cell Efficiencies (Solar Industry Magazine, October 2014), Michael Puttre suggests that understanding trends in the efficiency of PV cells is instrumental to understanding the future economics of solar energy.  This is unequivocally true, but it is often accompanied by the implication that one can do little more than track such developments after the fact.   Fortunately, a small cadre of specialists in the fields of strategic technology planning and technology intelligence have invested careers studying the dynamics of technological advance and have honed analytical approaches to characterize the state of the art (SOA) and predict the future direction and rate of advance in technologies of interest to their businesses.  This field of endeavor, often known as technological forecasting, consists of numerous extrapolative and normative techniques for predicting the direction and rate of technological advance in a given field and for assessing emerging technologies.  Importantly, for our purposes, these approaches have been shown to be particularly amenable to analyzing advances in renewable and alternative energy technologies, and the growth in PV cell efficiencies presents us with an ideal application.

Mr. Puttre’s article makes clear the need to understand advances in PV cell efficiencies and their importance to reducing the cost of solar energy.  But, with the plethora of PV technologies available, understanding the landscape can be difficult.  Particular varieties of silicon and thin film dominate the landscape now, but for how long?  The history of technological advance is replete with competing technologies vying for dominance in the marketplace and the current energy arena is no different.  For example, perovskites have recently garnered much attention in the press and appear to be on a steep upward trajectory.  How do we assess their potential in comparison, not to where the incumbents are today, but to where they will be in the future?

Most people have heard of Moore’s Law which describes the exponential growth in computing power over time but few know that Moore’s Law is merely a singular application of a broad class of growth models that apply to technological advance in general.  Fewer still know how to apply such models to the vast quantity of technology trend data that has become available in photovoltaics, wind energy, energy storage, and a host of technologies of interest to energy planners, utilities, developers, manufacturers, researchers, R&D managers, strategic planners, venture capitalists, and investors in emerging technologies.

Is there a Moore’s law for energy in general and PV in particular?  Of course there is.  The problem is there are many, and the first order of business is to adequately define the technology of interest – think silicon vs CdTe vs CIGS vs organic PV vs etc., etc., etc. – and the metrics that will allow you to assess their performance over time.

But, there is more to it than simply turning such technology assessments into a data dredging exercise.  It is common to consult with individual “experts” but unfortunately their biases often limit, albeit unintentionally, their ability to provide an objective picture of technological advance in a given field.  More worrisome, perhaps, would be relying on overpriced reports from the big market research houses whose generally optimistic growth projections are typically unsubstantiated.  Fortunately, more rigorous approaches for aggregating the diverse opinions and experiences of multiple experts are available to help arrive at a more complete picture of future advances in technologies of interest.  And, combining these qualitative approaches with the aforementioned trend analyses can equip technology planners with a fairly robust suite of methods to analyze emerging technologies and plan technology investments.

It is incumbent on those who are making and managing investments in new technology, as well as those who are at the heart of contributing to such innovations, to have at least some understanding of the dynamics of technological advance to help guide their decision making.  The tools to achieve this are available.  And, it is not so much that a given forecast must be proved accurate, but it is the learning gained from engaging in the exercise that enables better decision making.

So where do you start?
  1. Determine the technological performance parameters that can help you describe technological advance (hint: sales growth is NOT a technological performance parameter).  For PV, cell efficiencies are a good place to start but there are others.  For wind energy, rotor diameter, hub height, and turbine nameplate capacities are also a good starting place.
  2. Obtain trend data on the metrics of interest but be careful not to mix different technologies.  For example, if looking at trends in the speed of aircraft, do not mix propeller driven aircraft with jet aircraft as they are fundamentally different technologies and this will only make a mess of your analysis.
  3. Understand where you are on the technology s-curve of the technology you are researching.  There is always some physical limitation to the performance of every technology.  Are you close to it? (See the figure below).  Know how and when to apply the proper growth models (Gompertz, Pearl-Reed, Fisher-Pry, etc.) to complete your analysis.
  4. If looking at the substitution of an emerging technology for an incumbent one, consider that such substitutions often take longer than expected – in spite of what you may read in the press about “game changers” – and it is not uncommon for such an attack to motivate improvements in the incumbent technology.
  5. Last, the use of such analyses in planning your technology strategy is only a starting point.  Work to understand what the data is telling you.  Most importantly, understand that trend is not destiny.


For years, as principal in Technology/Engineering Management Int’l (TEMI) I have taught the principles of technology forecasting and technology intelligence to researchers, planners, analysts, R&D managers and others charged with strategic technology planning, competitive analysis, technology roadmapping, technology scouting, technology assessment, and technology transfer.  On November 13-14, I will be teaching a 2-day workshop in Colorado to introduce other professionals in renewable and alternative energy (and other technologies) to the methods for characterizing and forecasting technological advance.  Course information is available at www.temi.us or by contacting me personally at rich@energystrategies.co.

Monday, September 15, 2014

Electrically charged tortilla chips?

OK, now for a light-hearted look at greenwashing with wind RECs that I just couldn't resist.  As a fund raiser, my judo club manages a concession stand at Denver Bronco games.  Sunday, upon arriving at the stadium, I found several boxes of the tortilla chips used for nachos which, as you can see from the photograph below, advertised "Now energized with 100% Wind Electricity."



Note that they did not claim to be powered by wind energy (equally unlikely) or manufactured with wind energy (more likely) but that these chips are actually energized with wind electricity.  Wow!

Now, I know the difference between an energized circuit and a de-energized circuit, so I wondered what might really be the difference between chips energized with wind electricity and those energized with conventional energy (to the extent that you can actually energize a tortilla chip at all).  Well, I then searched for a box of the chips we used to sell and, sure enough, the difference was amazing.  Below, you see on the left a basket of chips energized with 100% wind energy and on the right Brand X (which I can't really tell if they're energized using fossil generated electricity or just not energized at all). Clearly, the wind electricity energized chips are bright and colorful and Brand X is, well, you can see for yourself.


So, proof positive.  Tortilla chips energized with 100% wind electricity are better.  If you want to see for yourself, come by and visit the Northglenn Judo Club concession at the next Denver Bronco home game just inside the United Club Concourse at Mile High Stadium.

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.