My friend Brad Copithorne from the Environmental Defense Fund has been in the midst of developing this new OBR program and he had invited me to join these proceedings.  Take a look at some of Brad’s thoughts here.

OBR makes a ton of sense.  It’s a better version of the existing utility OBF program currently provided by PG&E, SoCal and SDG&E and several other leading utilities around the country.  While last year Groom Energy started talking to folks about how the DOE could spur the market by funding OBF, OBR looks like an even better solution.

With the current OBF model utilities loan capital to customers at low or no interest, funding their energy efficiency projects while gaining repayment through their existing billing relationship.  Monthly loan charges show up just as another line item on the customer’s regular invoice.  As most projects are fast payback, these three to five year OBF loans are cash flow positive from day one.

But the funding pool supporting OBF loans comes only from ratepayers.  As this capital gets allocated during slugfest utility/PUC negotiations (which have a lot more at stake) utilities are not positively biased toward OBF.  More fundamentally, as utilities are not chartered banks, lending is already outside their corporate charter.

Using the existing OBF model, CA utilities provided @ $32 million through 1,200 loans during 2011.

But CA policy makers know this amount is noise compared to the famous McKinsey 2008 estimate of $500+ billion needed to fund energy efficiency projects across the US.

So the new CA OBR framework proposes that outside bank/finance companies can enter the market, providing what could be unlimited loan capital for customer projects.  These bank/finance companies would fund projects upon their completion and have their loans repaid through the existing utility bill, like in OBF.  But here the utility operates just as the loan administrator, forwarding the customer’s monthly debt service payments back to the bank/finance companies (whose core business is making loans.)

While the debate on the details is still taking place (what happens if the utility itself goes bankrupt? are credit enhancements necessary for these loans? do the energy savings need to be guaranteed? etc.) it’s clear this model is already profoundly positive for two reasons:

1. People pay their utility bills - even during the current recession utilities experienced less than a 1 percent default rate for their billings, versus @ 5% rate for more traditional small business lending.  Which means that although OBR is still new and “unproven”, long-term these types of loans are very bankable (meaning low cost and packageable.)
2. Capital comes from professional sources.  These folks have a day job of assessing risk and loaning money to willing and bankable customers.  And this means that the loan terms can be longer, leading to “deeper” retrofit projects with longer, but still attractive and certain returns.  It also accommodates energy savings service contracts like our CESA.

So we’ll cross our fingers that the policy review goes well and California kicks off this new model, even if its not perfect.  And like other innovative, new energy related programs coming from the Golden State, we can expect to see it rolling out to other states across the US in the next couple of years.

While 2011 held the promise and controversy of continued utility smart meter rollouts, 2012 may end up becoming the year of submeter.

Coming on strong as part of the emerging Enterprise Smart Grid market, these devices, which provide visibility to energy consumption at a granular and trackable level of detail, are set to see faster adoption in the coming year.   As government, utilities, vendors and end-users have slowly shifted toward a “prove it to me” mindset, the submeter becomes the weapon of choice to document energy related performance.

While the devices themselves are not new, their use will expand as a result of growth applications which require their capability.  We’ll see them used more by:

1. Companies looking to gain visibility into the current energy consumption of their largest systems and into nighttime and weekend or “off shift” load
2. ESCOs providing measurement in their performance contract guarantees
3. Demand Response providers confirming for ISO/RTOs that demand has been reduced during events
4. Solar installers needing production detail to be eligible for solar RECs payments and
5. Commercial and industrial customers producing measurement and verification for their utility rebates
6. Industrial firms trying to allocate energy costs to specific product lines, cost centers or government contracts

In the past submeters have brought with them the challenge of data management and reporting.  We’ve seen Groom Energy customers who previously installed them across their facilities, but have no easy way to access the volume of information these meters continuously produce.  With 2011′s recent flurry of newly introduced multi-user, Internet accessible, database-friendly energy software management solutions, this burden of gathering, managing and providing easy reporting from these distributed submeters will now be reduced.

And once a manager sees the fabled “energy dashboard” showing submeter energy consumption data, you can bet that manager will be ordering a few more of them…

Thus far programs have generally been protected – but how much longer will it last?

In early 2009 Connecticut almost did it.  Facing a significant shortfall post the 2008 economic collapse then-Governor Rell was rebuffed in her attempt to grab an additional $26 million by raiding the state’s existing energy efficiency and renewable funding.  But the message was loud and clear.  We need money – how green do we need to be?

And California (the state with a long standing lead in renewable and efficiency incentives) last year watched as Proposition AB23 got considered and defeated – a bill attempting to repeal the state’s existing AB32 legislation (the Global Warming Act of 2006) which AB23 supporters said was costing too much money.

Like California, existing RPS funding in 30+ other states may be reconsidered as belts are tightened and voters choose between unemployment and healthcare benefits versus previously voter supported clean energy funding programs.

Specific green technology programs are susceptible as well.  Yesterday a $1 billion multi-year carbon capture and storage program in the UK came under attack.

So in 2012, when government austerity programs become the norm, will less-green states have the intestinal fortitude to continue to protect their green energy programs?

With this latest partisan gridlock in the face of a financial storm, its a fait accompli that we will see a December 31st expiration of the Section 1603 cleantech cash grant incentives.  Solyndra alone has put cleantech supporting Democrats on their heels and become a “reckless government spending” lapel button on Republican sport coats.  Rightly or not, large bookable losses from the DOE’s attempt to stimulate jobs make it harder for politicians to put Section 1603 in a cleantech jobs creation wrapper.

Which means the cleantech markets will need to rely only on tax credits, as opposed to grants, in order to weather the looming US austerity period, whenever our politicians decide its important enough to address.

Unless by chance they’ve signed up for Demand Response.

One of the main compliance hurdles faced by Demand Response providers is proving to the utilities that they’ve reduced demand during DR events.  The ISOs need to confirm that the load reductions have been reached or exceeded and without that confirmation the DR providers don’t get paid.  So to track their reductions, DR providers typically install their own sub-meters at their customers’ main meters.  These sub-meters are connected back to the provider’s network operation, either through the customer’s internet or a cell phone, and enable the aggregation of performance data for the ISO across all of the providers customers.

Sub-metering doesn’t come cheaply, but the good news for DR providers is that they need only front the initial capital cost, as they can deduct these costs from future monthly customer payments.  (Not surprisingly, many prospective DR customers learn about their sub-metering costs only as they are signing their contract.)

Ironically, the technical infrastructure DR providers use to initiate customer load reductions (the ultimate reason they’re getting paid) is a little less sophisticated. It’s called outbound calling.  ”Hello, this is your DR provider calling, we’re having a demand event, can you please turn stuff off or turn on your generator?”  While there is a current effort to make this more automated (called the OpenADR initiative) the phone remains today’s technology of choice.

But the bonus for DR customers, on top of the their monthly DR payments, is new visibility to main meter 15-minute interval data.  Rarely before have corporate managers had easy on-line access to this intra-day, intra-week and intra-month graphical display of their consumption.  And guess what happens when they see it?

They ask lots of questions.

Which is a good thing.

A thesis for Enterprise Smart Grid is that this type of engagement is only the beginning of the process.  Main meter visibility leaves the management team asking for finer granularity on where consumption may be happening – which can be gained through additional sub-metering.  And finer grained visibility leads to the need for finer grained control, in order to manage down the consumption where it can be avoided.  And this visibility and control ultimately becomes integrated into the organization’s objectives, with on-going measurement, more intelligent procurement based on newly reduced consumption and proactive energy efficiency upgrades for assets that warrant an upgrade.

So perhaps by signing up for DR customers gained something much more valuable than their monthly DR payments?

Things have really picked up since then.

Last week I attended Citi Group’s conference entitled “Innovations in Energy Efficiency Finance” in NYC – a day long event, just on this topic.  Co-produced by our friends at EDF, it was the actually the third time they’ve held the event – the first having 20 attendees, then 50, then this year almost 100.  The agenda covered Federal and State government initiatives, things happening around the world and the commercial and industrial market (Groom Energy’s interest area.)  The full agenda and some good observations can be found here.

It was reassuring to hear panel discussions confirm the view on the large market opportunity, where even early “competitors” aren’t yet running into each other in their customer negotations.  But you coudn’t miss an older gentleman, with an entire career in energy efficiency, commenting from the crowd that “when they were considering this approach 20 years ago” it made a lot of sense then too…It alerted even the most optimistic folks that the shared savings financing approach is not new, but remains a market of the future.  The collective hope is that this time adoption will be driven by larger potential energy cost savings and a more willing set of buyers and sellers.

Like any new financing model, buyers will have to trust that they’re getting a good deal in exchange for the perceived risk of signing a multi-year energy savings contract.  Unlike banking institutions, new companies like Metrus Energy, Serious Energy, Transcend Equity, Green Campus Partners and Groom Energy have not been around for decades.  To address the perceived risk, Transcend says that they perform their projects “open book” – allowing the customer to see actual retrofit costs and returns, so they know what’s behind the curtain.  Metrus often works through ESCO partners who presumably have long solid customer relationships.  Everyone on the panel claimed they were working through a large funnels of potential projects.

The most significant players yet to enter the market are the utilities.  As Groom Energy has learned, when utilities offer on-bill financing in order to accelerate energy efficiency projects, customers move fast to sign these deals.  It makes sense – customers are obviously less concerned signing finance contracts with someone who they trust, who bills them every month and who is likely to be around for a long time.  But thus far utilities seem not too excited to go beyond limited use of on-bill financing.  Although NY recently passed an on-bill financing initiative in their August Power Act of NY bill, it will likely be implemented only for multi-unit housing and residential retrofits and does not include shared savings.

Of course the bankers in the room are crossing their fingers this turns into a more mainstream market, where they can package and resell the energy efficiency obligations as blind pooled bonds.  Although this looks a lot like a mortgage backed security, we’ll expect it to have a better outcome.

via How Soon Until We See Energy Efficiency Backed Securities? | Enterprise Smart Grid

With only one Limited Partner (i.e. the US Federal Government) the fund raising process was fast, accelerated by the fact that we thought the US financial system was about to collapse.  Applying a unique investment approach, Bank and Automotive company CEOs were called, told how much money they would be receiving (whether they liked it or not) and to draw up the investment docs.  Not surprisingly, within a few months the fund was fully invested and it’s portfolio complete.

Now in 2011, with a forecast of only $652 billion likely to be recovered, LPs (taxpayers) are left debating was actually the investing goal?

Six months after TARP, President Obama funded his own, smaller but sexier $13 billion DOE Fund I (let’s call it DOEF )  through a $100 million Cleantech carve-out within the intergalactic $825 billion Federal economic stimulus program.  The remaining $87 million was delivered through job creating DOE contracts implementing everything from utility smart grid rollouts to nuclear waste cleanup to low income home weatherization.

DOEF made it’s goal to drive “US Cleantech leadership” by investing capital in the most promising organizations.  The presumption was that, like venture capital, grants could help spur R&D in strong market areas and, like private equity, loans could help later-stage companies to ramp their commercialization efforts.

But unlike TARP’s “call the CEO” approach, DOEF had to first issue broad RFPs, then consider a diverse set of responses, each with their own business, technical and investment merits.  And the applicant pool included for-profit venture capital backed start-ups and even large publicly traded companies, in addition to the DOE’s more typical grantee targets (DOE’s own labs and research universities.)

Like a newly announced business plan competition, DOEF’s launch spurred any company with “cleantech” in it’s vocabulary to stop in it’s tracks, study the RFPs, and begin completing the numbingly exhaustive grant and loan applications.  And if an applicant had existing capital or a VC on it’s board it immediately hired a DC-based lobbyist to increase it’s DOEF lottery ticket selection odds.

While the RFPs were intended to flush out the most promising technical ideas, their practical effect was to overwhelm the DOEF investment team (i.e. DOE technical staff) with sheer response volume.  I can remember being at the DOE’s offices in late 2009 and having a conversation with a senior official who commented that Steven Chu was pushing his organization to “figure out where it should all go, but $10 billion must be out the door by year-end.”  (It turns out today that the money didn’t get out as fast as they had hoped.)

Once they figured it out, DOEF handed out awards with much fanfare, marketing each of the hottest Cleantech categories where they wrote the biggest checks, including $250 million for A123 battery jobs in Michigan, Wind farms in Texas and the now infamous $500 million loan guarantee to venture-backed Silicon Valley based solar PV poster child, Solyndra.  DOEF historical funding amounts and their locations can be tracked here.

And while the selections were purely merit based, its remarkable how evenly the recipient’s were located across the US, allowing politicians to confirm for LPs (voters) that their regions each got their fair share.  How convenient that the best Cleantech researchers, companies and entrepreneurial ideas were perfectly distributed around the country.

As a first-time fund DOEF was funded on the promise.  Now two years later the strategy has moved to execution and the initial portfolio provides an early measuring stick.  There are obviously some big question marks.

Some of the biggest DOEF private equity type checks were written to fund building battery and solar manufacturing plants, with Solyndra already having gone bankrupt.  If a private equity firm had lost its $500 million investment within a year of funding the entire investment team would already be looking for their next job.  But the big miss highlights that the DOE is not in the best to position to identify and fund the winners, which mean more losses like this are likely.

For DOEF venture capital investments, you have to ask why companies like General Electric and Dow Chemical need additional R&D funding to accelerate their investment in cleantech?  And do VC backed cleantech start-ups really need DOEFs money to do what they’re doing already?    And if DOEF is the “first money in” is it likely they’ll pick the best team and technology ahead of the cleantech venture capitalists?

Last week’s SunShot program awards, a program intended to  “reduce the cost of solar by 75%“, made grants to both large multinational and VC backed companies, in addition to a bunch of DOE labs and research universities.  But should the DOE really be trying to directly bring down the cost of solar by backing new solar R&D?  Last I checked there were a fair number of VCs who have a business investing in this sort of technology.

If it’s ”cleantech leadership” the DOE seeks, let’s start with customer adoption, which drives R&D value, and therefore spurs R&D investment by all companies.  Instead of DOEF trying to quickly pick the technical winners now, why not instead implement a 10-year $100 billion Federal incentive program which supports customer investments and drives revenue for the winning companies.

The US Federal Government has changed position on the incentive model enough that investors and companies discount the chances that the latest incentives are really around for the long term.  As we’ve commented previously, Federal incentives for both renewable and energy efficiency investments must be continuous, predictable and bankable for the market to really invest.  Unlike DOEF, which needed to push money out as fast as possible, companies and managers take a little longer to make strategic investment decisions.

So before fund-raising for DOEF II begins, let’s change direction and shift the DOE out of venture capital and private equity and into defining long term strategic incentives which drive adoption and put the US in a more competitive position in the next decade.  The free market will respond, cleantech growth will follow and it will cost the LPs a lot less money.

But the Enterprise Smart Grid framework highlights that to operate most efficiently companies need Visibility, Control and Management Integration for both of these elements.  And here there’s a useful lesson to be taken from the information technology industry.

In the 1970′s corporations used time-sharing to access mainframe computing, paying on a per-minute, per-job basis – call it computing as a service.  A decade later, microprocessor advances made it financially practical to bring PC and server computing in-house.  By the late 90′s software as a service, using low cost Ethernet connected servers, made it equally attractive for companies to move their computing back out to the network, this time the Internet.

So over a thirty year period technology advances shifted the best economics for corporate IT from pay-for-service, to owning and back to pay-for-service.

Power stations (electricity as a service) predate corporate IT by almost a century, first being delivered in the late 1880′s.  Like the mainframe model, utility providers centrally manage a high capital cost system (a generator) and deliver the service (electrons) over the network (the electrical grid) with customers paying as they go for what they consume.  Generally they’ve had few alternatives to buying their electricity in this local utility pay-for-service model.  Only a handful of the largest industrials have been able to cost justify installing and operating their own on-site primary generators.  Also, in the last decade companies in deregulated markets have been able to hedge a portion of their electricity costs by purchasing third-party power generation.

With the latest solar PV technology advances (and renewable incentives) some have considered bringing a portion of their electricity generation back in-house.  But with today’s average US cost of $0.11kWh, the math still points to pay-for-service (i.e. solar PPAs) and that only in four to five states in the country.

Steam as a service (Saas) is less well known, but has also been in existence for almost a century.  The industry’s trade association (International District Energy Association) started in 1909.  Universities and hospitals have run their own steam systems for a long time; with Harvard’s Blackstone plant having been in service since the late 1800′s.  NYC’s ConEd network, operating since 1882, is the largest in the US.

As with electric utilities, the Saas model runs a centrally managed high capital cost system (a boiler or cogen plant) to deliver the service (Btus) over the network (physical steam piping.)  Technology has not changed so rapidly in steam generation, with the latest large boilers moving from @ 70 to 80 percent efficient over the last 50 years.  While 90% efficient systems are in development, their high cost likely make them impractical for quite some time.

The corporate alternative to Saas involves installing a large on-site steam boiler and retrofitting a building’s mechanical system.  Where PV is renewable, solid state and overproduction can be sold back to the grid, financially modeling on-site steam is more complicated, including estimating future gas prices, a total maintainance cost for a lot of moving parts and a less clear excess steam utility sell back model.  (For an reference point on the cost of running a 100-mile steam pipe network check out ConEd’s 2010 long-term investment plan)

Recently we performed an energy assessment on a 20-story New York City commercial building still using district steam from ConEd.  Our analysis confirmed a three-year 40% increase in our customer’s cost of steam, this coming principally through newly assessed demand charges.   So the bring it in-house payback model needed to forecast the future cost of ConEd steam versus the new boiler and retrofit cost, the future cost of gas at a 20% premium to ConEd’s high volume cost, the on-going maintenance costs, with the ConEd incentives which supported this retrofit.  (Another reminder of why utility incentives needed to be decoupled)

The simple payback was 5 years.  Which means NYC steam as a service has officially priced itself out of the market and we’ll be working with this customer to bring their “mainframe” in-house.

Another alternative for the largest corporate users is a pay-for-service delivered by a non-utility third party.  Like solar PPAs for electricity, these vendors specialize in owning, operating and maintaining large traditional boilers, chillers, cogen and electric generator systems for single or multiple tenants, selling chilled/heated water, electricity or heat with long term purchase contracts.  But these agreements do have their challenges – and don’t lend themselves towards a customer changing their mind after a few years.

In a world where utility rates and incentives are dynamic, energy costs are likely to be accelerating (after a three-year hiatus) and new energy technology development is being introduced, our engineers should expect to be performing more of this in-house vs. pay-for-service tradeoff analysis.

via Companies Buying Energy Services, The Math Works, Until It Doesn’t | Enterprise Smart Grid

How money can be used as a motivational tool is a long-standing OB research topic.  While even healthcare firms consider how to pay people to take better care of themselves, McKinsey’s post crash research highlights that financial reward is less effective than providing employees the opportunity to lead and recognition by management for strong performance.

With ESG Visibility and Control, companies can use real energy use/cost data as the basis for both types of motivational tools, financial and non-financial.  The most significant energy efficiency behavior changes will come when companies integrate all of them, empowering managers with authority (lead), recognizing their impact (energy savings) and using the savings as a quantifiable financial incentive (financial reward).

Depending on the type of business we see a few different ways to make this happen:

In Manufacturing facilities:

We’ve already commented on how line managers can use ESG energy data from their production lines as a new metric – energy cost per unit of product produced.  These managers already have the authority and incentive to act, but have lacked the management system to enable them to make the best decisions.  Once given this new data, behavior change can be driven by the motivation to direclty impact their P&L, a very quantifiable and measureable metric.  Obviously managment incentives are regularly tied to P&L, coupling incentive to behavior change.

In Commercial Office buildings:

Office environment facility managers, responsible for a BMS controlling all HVAC and other major systems, typically have the capacity, but not the authority nor financial incentive to reduce energy consumption in their buildings.  These managers are trained to avoid any complaints by a building occupant – their implicit management metric is how few complaints they receive.

But they also know that by shutting down systems during low traffic or unoccupied periods they can save energy.   Simple activities such as turning off the escalators at night, alternating elevators, or dialing down the A/C when less that a dozen people are in the cafeteria can save real money.  These can even be programmed into the BMS schedule.  But these facility managers need the authority to act and to be relieved of the misleading complaint metric.

How about providing them instead a direct financial reward for taking these actions and a company green team sign saying ”these escalators are off now, reducing our energy use by X annual kWh”?

In Retail Stores:

Many store managers already have direct incentive to manage floor sales teams using sales results as their measureable management metric.  Their activies are often geared around driving sales through effective promotions, the customer in-store experience and having the right products in stock.

By providing energy consumption and cost visibility tools to these store managers, a company can apply a new goal which, like sales, has a compensation impact.  During our research we’re learned of one large retailer who conducted energy usage competitions between stores posting results on the store’s backroom bulletin board.

In Distribution Centers:

By their very nature distribution centers are rarely occupied by large staffs.  While DC managers are in the position to understand their facility’s regular traffic patterns, they’ll now see how much can be saved by shutting down systems.  But they too need the management incentive to act.

With the right financial incentive, these managers can “micro-zone” their facilities, shutting down systems in low traffic areas, time-shifting fork lift charging stations, or reducing conditioning costs where dock doors are left open unnecessarily.

But in each of the above examples someone “higher up” needs to lead a new managment approach.  Authority and incentives get defined at the top – and that is where real Organizational Behavior change occurs.

via Money is Not a Bad Incentive for Energy Efficiency Behavior Change | Enterprise Smart Grid.

CEO’s got pictures taken in front of their newly constructed LEED Platinum corporate offices. Retailers reported higher foot traffic in newly constructed LEED certified stores.  The USGBC even extended their brand by introducing LEED-EB so companies could certifiy their current real estate portfolio to the green standard.  The LEED brand reinforced the “this company is green” image and, in case anyone forgot, a plaque at the building’s entrance reminded people everytime they entered.

Post the 2008 market collapse we saw customers quickly drop their LEED efforts, focusing instead on Energy Star building certification.  The Energy Star brand is an even more visible green brand, they were already using  portfolio manager as part of the LEED process, and the certification process would likely yield real energy savings, a financial payback from the certification process.  It was a natural shift – plus they still got a plaque.

With ISO’s recent introduction of its 50001 Energy Management standard we’ll can speculate that this brand may now also be gaining a greener image.

Today the ISO brand is most uniquely associated with quality managment.  It’s programs are embedded as part of large global manufacturers’ culture, with many corporations proudly displaying their ISO 9001 certificate in the lobby of their headquarters.  So its not a surprise that the ISO 50001 pilot program included companies like Alcoa, Bridgestone, Schneider Electric and Volvo.  And it doesn’t hurt that the DOE is throwing its support for the standard as well.

As we’ve seen with sustainability reporting like the Carbon Disclosure Project, the next lever for ISO 50001 may come as it gets included within RFPs, supplier certifications and international trade contracts.

And when that happens make room for another plaque at the corporate headquarters.

via Like LEED and Energy Star, Can ISO 50001 Become A Green Brand? | Enterprise Smart Grid.