EDGE Distributed Energy Advisory Q2 2015

� How can developers strategize for YieldCo

acquisitions?

� Progress in standardization efforts for com-

mercial solar.

� Hybrid resources and microgrids: dealing

with financing challenges.

� Where are the opportunities for real estate

firms and distributed energy?

� How are green banks emerging as sources of

finance?

� U.S. regions poised for growth – progress in

the Southeast.

� What are the key distributed energy policy

developments in Washington, D.C. and the

states?

� Our take on longer term global trends push-

ing the distributed energy transition.

Technology, financing and market innovations are disrupting the energy markets, creat-

ing massive opportunities for deployment of distributed energy projects and services.

EDGE Advisory provides current market intelligence analyzing innovations at the cut-

ting edge of distributed energy finance, along with summaries and industry expert inter-

views discussing federal and state policy developments impacting these markets.

Published by the Energy Finance Practice of Sullivan & Worcester, LLP

Jim Wrathall & Elias Hinckley, Editors

See our blog at: www.energyfinancereport.com

Editors' introduction: View from the EDGE

Quarter 2 / 2015

EDGE Finance AdvisoryDistributed Energy Finance Report

Edgedistributed energy intelligence

Topics in this issue:

EDGE Finance Advisory Q2 / 20152

Page 3 How YieldCos are changing the market for developers

Page 5 Will commercial solar become more financeable?

Page 8 Financing for hybrid solutions and microgrids

Page 12Insights on Green Bank programs: Interview with Bert Hunter, Connecticut Green Bank

Page 14 Opportunities at the intersection of energy and real estate

Page 16 Economics of combined heat and power - a real estate perspective

Page 19Federal Roundup: Looking down the road with 38 North SolutionsInterview with Katherine Hamilton and Jeffrey Cramer

2 Global trends in the distributed energy transition

Page 24Regional focus: Green Tea Coalition supports renewables inroads in the Southeast

Page 25 Report from the States

In this issue:

Published in conjunction with the World Alliance for Decentralized Energy Content provided by Sullivan & Worcester LLP

3

HoW YiELdcos ArE cHAnGinG tHE MArKEt For dEVELoPErsIn the first half of 2015, YieldCos have continued to proliferate, with the structure taking on an increas-ingly important role in providing capital for distributed generation projects and businesses.

Though the market has not coalesced around a single definition, a

YieldCo can loosely be defined as a publicly traded company that

holds energy assets and has the goal of providing investors with

a steady dividend yield. YieldCos are typically organized as af-

filiates of entities which have asset portfolios on their books that

they wish to monetize, such as utilities and large-scale residen-

tial solar developers, and which are positioned to actively pursue

project development and acquisitions feeding YieldCo growth go-

ing forward. The ongoing affiliation assists in promoting manage-

ment continuity and ensuring that the YieldCo affiliate will have a

steady stream of future project assets. With the rapid growth of

existing YieldCos and numerous additional entrants coming into

the market, it is becoming more important for upstream partici-

pants to appreciate the implications of the YieldCo structure. In

this article we explore considerations and strategies for develop-

ers seeking to feed into the YieldCo pipeline.

There are at least eleven entities meeting this definition cur-

rently traded on the public markets in North America: NextEra

Energy Partners (NEP), Brookfield Renewable Energy Partners

(BEP), Hannon Armstrong (though formed as a REIT for tax pur-

poses) (HASI) (all traded on the NYSE); Pattern Energy Group

(PEGI), Abengoa Yield (ABY), NRG Yield (NYLD), TerraForm

Power, Inc. (TERP) (all traded on the NASD); TransAlta Renew-

ables (RNW), Capstone Infrastructure Corporation (CSE.TO),

Innergex Renewable Energy (INE.TO) and Primary Energy Recy-

cling (PRI.TO) (all traded on the TSX). Of these, a quick search

reveals that most are trading at +/- 1% of a 5% dividend yield,

though that is not a hard and fast range. In June, 8point3 Energy

Partners, a new YieldCo formed through a partnership between

First Solar and SunPower, completed its IPO, raising $420

million.

As a practical matter, those involved in renewable energy are excit-

ed about YieldCos because they reduce the cost of capital required

to acquire renewable energy assets. At the risk of oversimplifying a

bit, this is due to two factors: 1) the addition of liquidity to the mar-

ket; and 2) a reduction in return expectations due to the types of

investors which are creating that liquidity.

Why does this matter? Under the “old” model of renewable

energy investment, deal teams had to cobble together various

counterparties to take advantage of all of the economics of a

deal. These private market transactions were more or less be-

spoke, resulting in high diligence and service costs and requir-

ing substantial returns to offset project-specific risks. It was

not uncommon to see deals fail to receive financing even when

internal rate of return calculations predicted double digit yields,

particularly where one-off projects involved high or uncertain

risk profiles and transaction costs.

The YieldCo model has changed that. By aggregating mul-

tiple projects, risks are spread and overall returns are more

certain and predictable. Transaction costs are lowered over-

all through standardized approaches to deal processes and

documentation. As a result, YieldCos have created efficient

homes for the assets large companies formerly kept on their

balance sheets, allowed nascent entities to raise capital for ac-

quisitions, and reduced the cost of capital in the marketplace.

Further, YieldCos match up the time horizons of investments and

returns in clean energy projects, providing cash dividends consis-

tent with the desires of income investors.


In the midst of what is certain to be a complicated few years in

solar as the market looks past the potential expiration of federal

investment tax credits in 2016, developers would do well to culti-

vate sales pipelines that feed into best-in-class YieldCo partners.

There are several steps that developers can take to make sure

they are strategically aligning their projects with the desires of

potential YieldCo partners.

First, deals need to be priced to the market. If a developer wants

to sell off assets, either individually or as a portfolio, they need to

be priced correctly. This is easier said than done. Particularly in a

world where publicly-disclosed power purchase agreement rates

seem to be priced to the bottom, RFP winners have increasingly

thin margins priced into bids, and declining state and utility incen-

tives are the norm. While some have found it difficult to adjust,

developers have started taking notice of these new realities, and

are operating accordingly. Price compression, a natural event in

the maturation of a market, seems to be occurring in solar.

Even with attractive pricing, YieldCos, and their parent entities,

are selective when undertaking acquisitions. This is not surpris-

ing given the high volume of deals they transact, the sophistica-

tion of their deal teams and the stringent requirements of their

partners. Developers can take steps to ensure that they are ready

for their interactions with YieldCo counterparties. Addressing

these problems early in the development cycle is critical if devel-

opers wish to engage quality partners.

Developers also must ensure that their documentation conforms

to market expectations. While a number of solar industry-driven

initiatives, including SAPC (discussed below) and truSolar, have

pushed for standardization of documents and risk analysis, many

projects are plagued by “deal killers,” ranging from missing terms

to default provisions that don’t align with the expectations of so-

phisticated counterparties, which could be remedied by utilizing

available resources. Increasing numbers of developers are using

standard documents. Others seek guidance from counsel to en-

sure their document suites are market-ready. Still others utilize

documents provided by entities they wish to sell to, though this

requires collaboration.

Developers can also take steps to ensure that key aspects of their

deals have been finalized before presenting them to potential

partners. Far too often, developers present projects to the mar-

ket as “shovel-ready” when necessary permits have not been

received and documents are still under negotiation. While some

finance partners have an appetite to collaborate with develop-

ers before the shovel-ready phase, including by providing at-risk

development capital, it is critical that developers are honest and

clear about the key deliverables that need to be obtained and

pressure points that could arise.

Given the proliferation in YieldCos and their expanding role in

the market, distributed generation project developers will be

increasingly reliant on YieldCo acquisitions in supporting asset

turnover. Developers and aggregators in the smaller and mid-

size distributed markets will benefit by anticipating and meeting

YieldCo parameters, through early collaboration and by obtain-

ing guidance on the relevant market and documentation factors.

In the event that the 30% ITC is not extended by Congress, these

considerations will become even more important as deal activity

is expected to pick up through 2016.

5

WiLL coMMErciAL soLAr BEcoME MorE FinAncEABLE?While solar has been exploding over the past few years, the small commercial segment of the market - including installations at apartment and office buildings, small businesses, factories, warehouses, and hospitals - has been slow to develop.

The residential solar market, built on standardized transactions

and easy access to financing supported by FICO scores, is red

hot, as large investors with cheap capital are attracted to homog-

enous amassed projects and the perception of well-understood

credit risk. The utility scale solar market also continues to grow

(despite fewer available long-term power purchase agreements)

on the strength of declining costs and abundant liquidity in the

form of low cost capital driven significantly by YieldCos.

The small commercial market involves transactions that can be

as complex and expensive to execute as large projects, but lack

the economic scale to absorb the associated transaction costs.

Standardization, which has brought down costs for residential

pools, has been slow to emerge in parallel form to support the

small commercial market. Unrated or high credit risk of diverse

power buyers has kept traditional (and inexpensive) capital

sources away from this part of the market. The result is a small

and fractured segment that has been underserved while the bal-

ance of the industry has grown rapidly.

However, the challenges for small commercial solar are slowly

being tackled. Better transaction processes and models for

standardization are emerging, along with new tools such as

revitalized PACE (Property Assessed Clean Energy) programs

and innovative approaches to managing credit risk. Margins in

commercial solar are currently higher than in either utility scale

projects or residential pools. This confluence of opportunity

and solutions is redrawing the commercial market and attract-

ing new and cheaper capital. Commercial is poised to become

the new hot solar market.

The importance of standardizationStandardization and streamlined transaction processes are vi-

tal to the commercial market. Limited success in this segment

has thus far mostly been with large corporations, which would

negotiate standard agreements across many sites. For others,

legal and transaction structuring fees have crippled the eco-

nomics of many commercial-scale projects. Standardization is

critical for accessing cheap financing sources, as large investors

have little appetite for small one-off projects, and consistency

of project and supporting documentation is necessary to aggre-

gate multiple projects into appealing pools for these investors.

Two years ago, the U.S. National Renewable Laboratory (NREL)

assembled the Solar Access to Public Capital (SAPC) coalition,

brought together to build model transaction documents to pro-

mote standardization. SAPC developed a set of model contracts

for solar projects, including power purchase agreements (PPAs)

and lease agreements for third-party ownership.

The Solar Energy Finance Association (SEFA) was later formed,

with the goal of helping refine these standardization efforts to

meet the requirements of the financing industry for direct in-

vestment, as well as access to secondary market options like

securitization. In the commercial area, there has been interest

and evolution built off both these efforts. While the output has

not yet attained the uniformity of products in the residential so-

lar market, much progress is being made.


Solving the creditworthiness conundrum

As the commercial space begins to benefit from standardization

and better credit management tools, new sources of capital are

being attracted to this segment of the market. Companies are

seeing a new influx of community banks and credit unions start-

ing to fill the void for both lending and tax equity for small com-

mercial projects. Local financial institutions can lean on long-

standing relationships with the small commercial businesses.

Institutions which previously have financed projects are in-

creasingly willing to expand on existing relationships to provide

financing for additional commercial solar projects.

This engagement by local financial institutions appears to be

part of a larger trend. Bank of America and SolarCity are work-

ing to facilitate smaller and community banks to enter the mar-

Innovative approaches bring new sources of money

At the same time, companies active in the small commercial

market are aggressively working towards consistency in docu-

mentation and process on the limited deals that they have been

able to execute. One challenge to standardization is the poten-

tial misalignment of interests of the solar provider, the build-

ing owner and service providers such as lawyers. In residential

markets documentation is simple and offered on a take-it-or-

leave-it basis. By contrast, commercial building and business

owners view a solar offer as a negotiation around terms of proj-

ect documents, typically negotiated by lawyers from both sides.

The lawyers negotiating on behalf of the solar buyer may not be

well versed in solar projects (and often both sides’ legal support

is focused on risk management as an absolute concept and not

on the materiality of the solar commitment). This void too is

being filled. Efficiency in the solar market is broadly improving

through an understanding in the common tension points within

negotiations, allowing for the development of processes and

documents that are easily explained and modified – and a few

lawyers (and some competing services) have even begun to take

responsibility for owning this part of the process and are provid-

ing certainty for both the cost and the production of consistent

project documentation.

Collectively, these developments are moving towards real stan-

dardization across portfolios of commercial projects. As we have

seen with residential, this success in standardizing the process

and documentation will act as a positive feedback loop for the in-

dustry – as more projects are brought on line, the ability to stan-

dardize, and to demand more standardization with potential solar

buyers, will naturally increase. The result will be an accelerating

reduction in the transaction costs in this segment of the market,

driving an expanding pool of potential new investors and lenders.

Commercial transactions also face greater complexity in assess-

ing credit risks. There is a great need in the solar market for a pro-

vider of FICO-like “shadow credit ratings” reducing the time and

expense of assessing these risks. Defining credit risk, especially in

a way that more conservative investors (like banks and other tax

equity investors) will accept, has been a consistent challenge for

the commercial solar market. But this too is changing.

A new credit measuring tool has been launched by Sparkfund,

a Washington, D.C. startup, which has developed software ap-

plications for building condensed credit scores for small com-

mercial customers. Sparkfund’s program was designed for

the energy efficiency market, but can also be applied to solar

financing. This alternative credit review is aimed at building

aggregated pools of credit risk for developers to support debt

and equity capital investments. Other database and informa-

tion technology companies are also moving to serve this need.

In many states, PACE funding allows customers to finance a

solar system and pay for it as an addition to their property tax

bill. PACE solves the creditworthiness problem by tying the

repayment of the solar to property tax, making it much more

likely to be repaid than if structured as a separate financing

for just the solar property. PACE captured the imagination of

the solar industry several years ago. However, Fannie Mae

and Freddie Mac, followed by other mortgage underwriters,

refused to allow PACE liens to have priority over mortgages

on the associated properties and the concept lay dormant

for several years. Of late, however, a number of states have

become much more comfortable with PACE, especially in

commercial settings, and it is has become a valuable tool for

entities that do not have a FICO-like score or a large balance

sheet of assets.

7

Achieving success in distributed energy projects requires more than an innovative financial model. Transaction efficiencies are a key determinant of suc-cess. Regulatory and transaction costs for lawyers, bankers and accountants can make or break a proj-ect, or even a business model.

Transaction processes should be carefully tailored to match the economics of distributed energy projects and investments. For more information on innova-tive approaches to achieving transaction efficiencies, please visit:www.edgefinanceadvisory.com

ket by establishing a $200 million program that allows these

banks to participate in tax equity pools. This relationship

between Bank of America and the smaller investors is facili-

tated by projects fitting inside a standardized framework and

leveraging local financial institution knowledge of the solar

customer’s credit worthiness. Others are exploring financing

platforms for the small commercial solar market both as direct

investors and also with the strategy of aggregating projects

and selling into the secondary markets.

Smaller commercial solar has tremendous potential. Improved

processes for standardization, innovative financing tools, and

a wave of new investors are on the verge of opening up this

huge new market. Because small commercial has been rela-

tively untapped, the available returns for the companies and

investors that can realize will be higher than in the more es-

tablished solar segments, with further potential returns open

to those who can crack open the secondary markets. This will

have ripple effects throughout the distributed energy and en-

ergy efficiency marketplace as the lessons of how to stream-

line and standardize small commercial projects are exported

to parallel markets.


FinAncinG For HYBrid soLutions And MicroGrids

Hybrid solutions – combinations of multiple generating and power management technologies – are creat-ing new value propositions beyond single technology systems.

A form of hybrid, the concept of a mi-

crogrid generally refers to an electric

grid within the larger utility system that

interconnects multiple power users with

each other and with local power gen-

erators and/or storage in an integrated

system. Microgrids frequently have the

ability to “island,” by automatically dis-

connecting themselves from the larger

grid during system emergencies while

maintaining reliability within the mi-

crogrid area.

2015 to date has seen major advance-

ments in deployment of hybrid distrib-

uted energy resources and microgrids,

along with accompanying innovation in

financing for these solutions. Recent

milestones have included:

� SolarCity’s offering of “microgrids as a service” – combining solar generation, inverters, Tesla lith-

ium-ion battery storage and power management software into an integrated solution, supported

by zero-payment financing and ongoing operations and maintenance.

� SunEdison, in March, expanding its third-party financing options for battery and inverter systems

co-located with solar projects; SunEdison and Imergy also announced an offering combining so-

lar and flow batteries to provide microgrid solutions in developing countries, starting with a goal

of serving 20 million people in India.

� ViZn Energy joined with LFC Capital to finance solar PV and energy storage for commercial and

industrial participants, reportedly providing up to $5 million in funding through an operating lease

model to finance installation of solar and flow battery systems.

� Green Charge Networks has deployed a model whereby it will fully finance installation of energy

storage and power management systems to reduce peak load and provide backup power, with

payment out of shared utility fee reductions over the first decade.

� Sunverge Energy announced deployment of its Solar Integration System, an integrated energy

storage platform which combines solar inputs, power electronics, lithium-ion storage battery

storage, and cloud-based software controls and analytics.

� Stem, a company that finances distributed energy storage systems for commercial industrial cus-

tomers, has raised more than $60 million in equity capital to date, including a $12 million round

led by Mitsui & Co. in April.

� Texas utility Oncor has teamed with S&C Electric and Schneider Electric to engineer a “smart mi-

crogrid” solution combining solar, wind, storage and diesel backup

Institutional investors are committing substantial financing for

these kinds of projects. For example, Stonepeak Partners Infra-

structure Investors, a $1.7 billion private equity firm, announced

a $250 million fund to finance microgrid projects. The fund is

partnering with developer Energizing Co. for investment in util-

ity distribution microgrids of up to 145 MW. Another financial

participant is Clean Fleet Investors, a fund focusing on project

financing transactions ranging from $3 to $10 million, which is

9

actively seeking storage and microgrid investment opportunities.

States are getting into the action as well. New York’s Green

Bank is expecting to provide over $800 million in funding for

clean energy projects through 2018, focusing particularly on

microgrid and high resilience projects. Connecticut's Green

Bank has a specific microgrid grant program, with $30 million

in grant funding authorized through 2016. California’s state law

AB 327 has required major utilities to prepare proposals for

integrating customer-sited generation, including microgrids,

through advanced distribution grid planning.

Expanding sources of financing will be critically important to

maintaining growth in this emerging sector. But hybrid dis-

tributed generation and microgrid projects raise unique opera-

tional, technology and regulatory issues that must be carefully

assessed in evaluating and structuring financing. The ability of

the financial markets to understand, accept and properly price

these factors will impact the pace and breadth of deployment

of these technologies.


Gating factors to financing microgrid and hybrid energy projects

Financial investors focus on several key gating and due diligence items in evaluating microgrid and hybrid projects.

Major considerations include:

Resource evaluation and costs. Fundamental considerations affecting performance and economic returns are similar to standard renewable energy proj-

ects such as solar and wind, but are made more complex by the additional interplay of information and cybersecurity tech-

nologies, added technology risk, and the regulatory overlay for transmission and distribution facilities.

Power control technology assessment.Commercially proven hardware and software for load management and control are vital to financing. As microgrids repre-

sent new points of entry to the grid, integration of cybersecurity software into systems will enhance the value of the asset

to the grid, and indeed may become compulsory in some jurisdictions. The more robust the software is in controlling capac-

ity and responding to demand signals from dispatch centers, the better the prospects for financing.

Portfolio aggregation. Aggregating hybrid and microgrid assets provides operating economies of scale and mitigates single contingency outage risk,

both of which are attractive to investors and lenders. Standardized technology solutions can be installed in a single location

for deployment on multiple projects. Aggregation of assets also allows a developer to more quickly tap into the YieldCo mar-

ket to monetize value, and to achieve cost savings through technology replication and document standardization

Valuation of grid services. Microgrids can provide substantial benefits back to the grid, in the form of peak demand management, ancillary services such

as voltage regulation, reactive power and frequency response, and deferred capital investment in distribution and infrastruc-

ture costs. Are these services fairly valued (or valued at all) in the applicable utility/PSC setting? As grid management is a core

service of most regulated utilities, an opportunity exists to develop hybrid investment structures in partnership with the in-

cumbent utility. Innovative financing solutions can be used to permit these assets ultimately to reside in a utility’s “rate base”

but without imposing rate shock on ratepayers which can be the single largest regulatory impediment to utilities building out

needed infrastructure.

Valuation of grid resilience and security functions. Does the financing framework attempt to quantify the value of greater reliability and protection against disruptions? A key

metric for valuation and rate negotiations is how the same asset would fare if granted an incentive or performance-based

rate of return if it were to be built by a regulated utility.

11

Importance of regulatory and jurisdictional issuesMicrogrids present complex regulatory issues, as they involve

the erection of wires, substations, conduits and other facilities

that require rights of way, easements and interconnection to

the larger grid. Unlike utilities, private microgrid owners do not

enjoy the powers of eminent domain. Nor can they “rate base”

their investments like utilities. Microgrids should be incor-

porated in a manner to avoid redundancies and overlaps with

utility planning and facilities. Other obstacles include lack of an

existing regulatory framework, unclear safety standards, utility

opposition and permitting delays. With respect to utility oppo-

sition, three factors can be particularly problematic: (1) exces-

sive fixed and stand-by charges; (2) interconnection barriers;

and (3) restrictions on rights to sell back to the grid.

Potential federal, state and public utility commission require-

ments must be carefully evaluated. If a microgrid is intended

to distribute to multiple end-users, a project may fall within the

definition of a “public utility” or otherwise be a regulated en-

tity under state law, triggering PSC jurisdiction and statutory

constraints, potentially including restrictions prohibiting retail

electricity sales. Many states provide electric utilities with the

exclusive right to provide retail electric services in their service

areas, provisions that could be asserted to bar third party op-

eration of hybrid and microgrid systems.

The California Public Utility Commission (CPUC) has released

a white paper, Microgrids: A Regulatory Perspective, 2 discussing

many of the important regulatory issues, including:

� Relationship with the incumbent utility

� Interconnection rules

� Retail tariffs and bundling

� Standby charges

� Departing load charges

� Approaches to metering

� Utility cost recovery

� Sitting and grid backup

The CPUC paper and similar resources, along with professional

consultation, can help market participants identify and evaluate

the suite of regulatory risks at the state level. Federal require-

ments also must be evaluated, particularly if a microgrid intends

to transmit at a transmission level voltage (e.g., 69kV or higher)

or sell electricity into the wholesale power market.

Transaction structures and costsFinancing frameworks for hybrid distributed energy and mi-

crogrid projects present unique considerations and may require

time to gain acceptance by money center banks and other finan-

cial institutions. Leasing, shared savings, and portfolio models

can borrow from existing approaches used for single-technolo-

gy solar and wind transactions. Developers and investors look-

ing at particular states or projects also should seek to identify

existing programs seeking to develop standard rules and proce-

dures for addressing the regulatory issues above. To the extent

such efforts are in process, there may be opportunities to shape

the standards and ultimately to optimize prospects.

The market for hybrid and microgrid development and invest-

ments remains in its infancy. For those who are able to manage

the risks described above, substantial opportunities await.

2 http://www.cpuc.ca.gov/NR/rdonlyres/01ECA296-5E7F-4C23-8570-1EFF2DC0F278/0/PPDMicrogridPaper414.pdf


insiGHts on GrEEn BAnK ProGrAMs: Interview with Bert HunterExecutive Vice President and Chief Investment Officer, Connecticut Green Bank

“Green banks” – financial institutions chartered with an

express mission of funding clean energy and distributed en-

ergy projects – have been established in a number of states,

including Connecticut, New York, New Jersey, California,

Hawaii and Maryland. These special purpose banks provide

financing for distributed energy resources, including com-

bined heat and power, fuel cells and renewables, in addition

to energy efficiency measures, through mechanisms such as

subordinated and revolving loans, loan guarantees and ag-

gregation facilities. We asked Bert Hunter, Chief Investment

Officer of the Connecticut Green Bank, to fill us in on the lat-

est developments:

EDGE: The Connecticut Green Bank has

been having a major impact providing fi-

nancing for clean energy in Connecticut.

What role do you see the Bank playing, and

which of your current financing programs

are having the most impact?

BH: At the Green Bank we see our role

as maximizing the impact of state re-

sources. Our funding comes mainly

from electric utility customers (a sys-

tems benefits charge of about $8 per

household per year), so we refer to it as

limited rate payer resources. We seek to

use those limited rate payer resources to

leverage private capital, to grow clean

energy markets quickly. The goal is to

boost private sector investment in clean

energy, creating a suite of benefits in-

cluding job creation, economic develop-

ment, climate benefits, and affordable

energy prices for consumers, or at least

to lower their expenditures to the extent

that they become more energy efficient.

Our goal is to meet these objectives in a

way that is sustainable, through financ-

ing programs as opposed to handing out

rebates and incentives, so the capital

comes back to the Green Bank where we

can redeploy those resources over time.

One reason we were established is that

Connecticut is challenged with high pric-

es for electricity. We have the highest

electricity prices of the lower 48 states

in fact. At the same time we have a gov-

ernor and a legislature that have estab-

lished very ambitious clean energy goals.

When we speak of clean energy here in

Connecticut, we think in broad terms.

We’re focused on renewable energy

technology, especially solar PV, but also

technologies such as fuel cells.

Where are we having the most impact? I

would really say in three key areas. One

is residential energy efficiency, another

is residential solar PV, and the third is

in the commercial/business sector, our

commercial PACE, or “C-PACE”, program,

which provides funding for energy ef-

ficiency, solar and renewable energy

projects for commercial and industrial

properties.

We have a $30 million dollar program

with 10 community banks and credit

unions to provide unsecured loans to

homeowners at affordable rates of up to

12 years to finance energy efficiency, so-

lar PV and a range of other energy saving

measures. Typically the rates for these

loans range from 4¼% for a five-year

loan, to 6.99% for a 12-year loan, which

are great rates for an unsecured loan.

But it even gets even better if you bundle

solar with energy efficiency at the same

time -- if a homeowner does that under

a current program we’ve got going with

these local lenders, they’ll lend at less

than 3% for 10 years.

In another initiative, we created the first

dedicated solar loan product, not se-

cured with a lien on the home or tied to a

particular solar panel product: a 15-year

6½% loan product, financed by crowd

funding. Working with US Bank provid-

ing tax equity and a syndicate of banks

led by First Niagara, we put together a

$60 million dollar solar PV fund for resi-

dential as well as commercial scale solar.

The real innovation there was creating a

facility for smaller commercial transac-

tions. We worked with US Bank and the

lenders to develop an underwriting box,

if you will, to permit the Green Bank to

underwrite these credits, and they pret-

ty much broke into the two categories,

including a host with and without credit

ratings. The projects without a credit

rating get secured by C-PACE. The Con-

necticut Green Bank was the first to do

this.

Also, our C-PACE program has been very

successful. The program works by pro-

viding up to 100% financing for terms

of up to 20 years for energy efficiency

13

and renewable energy investment to the

property secured by putting a benefit as-

sessment lien on the property. For prop-

erty owners, it doesn’t matter whether

they’re going to be there for three years

or twenty years, because when they sell

the property, the obligation to repay the

financing for the energy efficiency and

renewable energy measures that are

fixed to the property will become the ob-

ligation of the next property owner. The

savings stay with the property and so

does the obligation to pay. We’ve done

$75 million dollars in transactions in 18

months at over 100 different properties

throughout the state. We are known for

this as the fastest growing and largest

commercial PACE program in the coun-

try.

EDGE: Is there some obstacle that other

states are seeing to commercial PACE that

needs to be overcome to make this more

widespread?

BH: It comes down to how the PACE

programs are structured, and whether

transactions can be done with a straight-

forward application process and docu-

mentation process. We worked on that

very, very hard with potential lend-

ers and capital providers. We put the

program together in a way that is very

friendly to property owners and easy

to understand. We try to take the pain

out by making it a very routine, simple

and easy process. Uniformity across

the state is also important. Contractors

love it because they know once they’ve

got the routine down for financing, they

can go anywhere in our state and finance

using C-PACE. In some states, you move

from county to county, or even from,

from one taxing district to the next, and

you can have totally different documen-

tation, totally different rules. That’s not

a way to scale-up a market.

We also have a very rapid response to

applications. Property owners as well

as the contractors know that if they go

through this process the money is going

to be there and they don’t have to wait.

The Green Bank is going to start cutting

checks and fund the project. Projects

in other states sometimes have to wait

weeks for enough projects to be aggre-

gated before the C-PACE district will

then issue a bond and then provide the

financing for the property to apply it to

the program.

EDGE: Are there examples in other states

that you see are following the lead, doing

things that you see making good progress in

this area?

BH: California has a number of state-

wide programs similar to ours. Also,

New York has the Energy Improvement

Corporation (EIC) that they have estab-

lished, although I believe that is not an

open platform. Our platform is open,

so not only does the Green Bank lend,

but we also have what is called a stan-

dard offer that we make available to

capital providers if other lenders want

to come into the market and do C-PACE

financing. In the New York EIC model

I am pretty sure they control the fund-

ing mechanism through First Niagara

and Bank of America. I see other states

moving along. Maryland is trying to

establish a statewide program. New

Jersey and Massachusetts are looking

to enact legislation. Rhode Island has

established an infrastructure bank, and

there we have talked to them because

they want to establish a C-PACE pro-

gram. So it is very popular, but I would

say that the states that are leading the

way right now are California, Connecti-

cut and New York, as well as Florida.

Those are the four main states where

commercial PACE activity is alive.

EDGE: Looking forward, are there addition-

al innovations, or new structures or other

approaches that are on the horizon for the

Bank?

BH: Yes. To stick with the C-PACE theme

for the moment, the market in a short

time period has outgrown the ability of

our balance sheet to keep up, so we have

requested proposals from the capital

market for facilities to fund the C-PACE

program. We were showered with pro-

posals, thankfully, from many banks, in-

vestment banks, broker dealers and the

like, offering anywhere from $100 mil-

lion to $200 million and more in funding

for these transactions including some

securitization facilities. We are in the

process of closing the transaction with

the successful bidder. Stay tuned for

that. We also are in the process of issu-

ing green bonds to finance energy effi-

ciency improvements for state facilities.

Everything from state hospitals, cor-

rectional facilities, Department of Mo-

tor Vehicles or DMV buildings, agency

buildings; all of these are looking to do

energy efficiency improvements or so-

lar PV. We are going to start with a $40

or $50 million green bond and then we

will issue more as the program develops.

I would say that there is an entire eco-

system of energy efficiency and renew-

able energy providers that are benefit-

ing under this program. And not only

are homeowners benefiting, but also

businesses. We’ve seen the growth of

solar PV double year-by-year. In a state

like Connecticut, which suffered greatly

from the financial crisis, this has been

an important boost to the economy and

jobs, supported by Green Bank financ-

ing and the private capital that comes

with it.


oPPortunitiEs At tHE intErsEction oF EnErGY And rEAL EstAtEA wave of technology and innovation is fundamentally changing the way that building owners and other real estate investors are thinking about the role of electricity in real estate investments.

Since early in the 20th century, the

world’s electric systems have been based

on a model centered on large generating

stations, with complex transmission and

distribution systems to deliver electrici-

ty to users. Now we are in the early stag-

es of a fundamental shift, driven by tril-

lions of dollars of investment, from the

traditional centralized energy model to

a system that is significantly distributed.

This investment will manifest in several

distinct forms, including onsite power

generation such as solar or combined

heat and power systems; enhanced en-

ergy efficiency and energy management

tools; and on-site electricity storage; as

well as systems built around supporting

electrification of vehicles.

In the old model, electricity came in from

the wires and was a cost over which a build-

ing owner had either no control (in settings

like self-used and gross leased property,

where electricity might be paid by a build-

ing owner and recovered through higher

rents) or no real interest (as with net leas-

es, where a tenant is responsible for ener-

gy costs). As that model is being replaced,

the increasingly distributed energy system

is creating tremendous opportunities to

profit from this multi-trillion-dollar energy

market transformation.

However, who will own these assets and

how the profits will be allocated are is-

sues that are

far from settled

in these newly

emerging mar-

kets.

Traditional ener-

gy companies are

only just begin-

ning to embrace

the economic po-

tential of this shift – and will continue

to struggle to adapt, for a few reasons.

Utilities are subject to regulatory limits

on owning generation or energy manage-

ment tools inside a building and beyond

the meter where the sale of electricity

occurs. Utilities have been slow to em-

brace a market that represents demand

destruction for their core product and

does not build off of core skills within

these companies. Finally, the culture

of the traditional power business is one

built on glacial-like response to change,

in which advancements (if they occur)

take decades to unfold, making it very

difficult to react to what is now a tech-

nology driven market, producing new

technologies and new ideas around pro-

cess on a time scale measured in months.

New energy companies are emerging.

The current environment, with persis-

tently low interest rates, has made the

use of money extraordinarily inexpen-

sive, and investors have been willing to

enter parts of these new energy markets

at a scale and pace that has surprised

many as they search for new sources of

yield. The result has been several early

success stories among these new energy

companies. Residential rooftop solar

has been the most notable early success.

Deals are easily replicated with take-it-

or-leave-it approaches to documents.

Credit risk is pooled based on FICO

scores, just like mortgages, and the re-

sult is a market that can not only attract

capital, but one where investments have

successfully driven public stock offerings

or have been re-sold into the second-

ary market, further reducing the cost of

money supporting these projects.

One area where these new energy-fo-

cused investors have struggled to find

success so far is in the market for energy

projects associated with commercial and

industrial buildings. Finding consistently

credit worthy owners and tenants, along

with the complexity and expense of the

transactions, have presented the biggest

challenges. There have been some lim-

ited success stories working with very

large companies (where multiple sites

15

can be managed under a single transac-

tion process and credit ratings make

evaluating credit risk easy), but across

much of the commercial real estate mar-

ket we have seen limited activity, despite

the potential for very significant invest-

ment returns.

In the past year new groups of investors

have begun exploring this untapped part

of the market. Some real estate inves-

tors have recognized that these new

energy investments are remarkably simi-

lar to the underlying real estate invest-

ments that they serve. There are certain

identifiable operational risks, but once

these are controlled, the payment risk

is a combination of occupancy and ten-

ant credit risk – exactly what a building

owner already models to determine the

value of the underlying real estate in-

vestment. The energy investment can

actually enhance the value of the under-

lying real estate by reducing occupant

operating costs, augmenting cash flows,

and improving a tenant’s ability to pay

for property use.

These investments require a better un-

derstanding of the relationship between

building use and energy than has been

necessary for most real estate investors

to date. They also require careful struc-

turing for potential investors organized

as real estate investment trusts, or other

sophisticated organizational structures

and property management approaches.

Otherwise, the most significant differ-

ence is that these energy investments

can generate substantially higher rates of

return than the underlying real estate in-

vestment. For a real estate investor who

has already evaluated a property, layer-

ing on an energy investment to increase

returns has obvious appeal. An inves-

tor that is already comfortable making

the real estate investment understands

the loss, default, and occupancy risks of

a property, so adding a further layer of

additional investment return analysis

becomes a relatively easier proposition.

The emergence of this new type of real

estate-energy investor has broader sig-

nificance. The need for investment to

support the energy transition that has

just begun is immense – it is expected to

entail the largest deployment of capital

in human history, so there is ample room

for new participants, especially inves-

tors that are addressing underserved

portions of the market. By applying a

more sophisticated understanding of

real estate-related risk to the distrib-

uted energy market, these new investors

will rapidly and dramatically expand the

available capital for distributed energy

investments. With this expansion expect

a new class of energy companies and in-

vestors to become a vital part of our en-

ergy mix.


EconoMics oF coMBinEd HEAt And PoWEr: A Real Estate Perspective

With states adopting programs to encourage energy users to

install combined heating and power (CHP) systems, building

owners and asset managers are asking themselves the bottom

line question - how can CHP increase my operating income and

asset value?

Every building varies in energy use, energy efficiency and fuel

supply arrangement. Large users such as hospitals, universities,

hotels, offices and residential buildings each have unique con-

siderations. CHP presents an integrated alternative to (a) using

on-site oil or gas boilers for heating while (b) purchasing elec-

tricity from the local utility. CHP generally provides a cost ef-

fective way for a building to generate its own electricity, heating

and cooling by sequentially running a single fuel input through a

combined power and heating system. CHP can increase a build-

ing’s operating income, and in turn increase its asset valuation.

CHP will make the most economic sense when (1) a building’s

thermal requirements are high, (2) its boilers are aging, (3) elec-

tricity prices are greater than $0.10/kWh, or (4) major boiler

retrofits are needed to satisfy new environmental regulations.

Typically natural gas fueled CHP systems can achieve system ef-

ficiencies of around 80%, depending on steam load.

To understand the economics of CHP, assume a commercial

building with 500,000 square feet charging rent to its tenants at

$50/sq. ft., inclusive of energy. We assume delivered natural gas

at $11.00 mmBtu ($5.50 commodity), and electricity purchases

from the local utility at $0.20/kwh.

Using the assumptions set forth in Table 1, the building will

spend approximately $3 million annually in energy expenses,

and have an annual net operating income of approximately $16

million. If the building’s revenue increases by 6% per year, the

asset would be valued at approximately $271 million.

Building w/o CHP Building w/ CHP

Square Feet 500,000 500,000

Annual Energy Usage per Sq. Ft. 25 kWh/ 150 btu 25 kWh/ 150 btu

Electricity Cost per kWh $0.20/kWh

Annual Electricity Cost $2,500,000

Annual Heating/Cooling Cost $825,000 $825,000

Annual Energy Savings $0 ($831,250)

Net Operating Income $16,250,000 $17,081,250

Annual Increase (decrease) in NOI $0 $831,250

NOI Increase over Life of System $12,468,750

Asset Value@6% $270,833,333 $284,687,500

Property Value Increase $13,854,167

� Table 1: Assumptions3

3Actual savings will be determined based on the actual consumption and load patterns of the building, what it actually pays for its electricity and gas or steam, how energy

efficient the building is, the availability of natural gas to the building and other site-specific factors.

17

By installing a CHP system, the building will begin to generate

its own electricity while using the waste heat from electricity

production to meet its thermal demands (heating, domestic

hot water and potential absorptive cooling). The higher the

building’s thermal requirements, the more cost effective CHP

will be as the cost of electricity per mmBtu of fuel declines.

The corollary is that the cost difference between buying elec-

tricity and generating it on-site increases, thereby reducing

utility expenses and increasing operating income.

The key economic relationships determining the profitability

of CHP are: 1) the grid price of electricity; 2) the efficiency

of the CHP unit (expressed as a “heat rate” in mmBtu/kwh),

and 3) the price of fuel. This relationship is shown in Table

1. Based on our usage assumptions, by installing CHP the

building would increase its net cash flow by approximately

$830,000 annually. This in turn will increase the asset val-

ue by approximately $14 million. The CHP system payback

would be approximately 7 years, based solely on energy sav-

ings without considering incentives or tax credits, compared

to the cost of installing new boilers, which would be approxi-

mately 10 years.


Given the financial attractiveness of us-

ing CHP, there remains the question of

whether it makes business sense to incur

the higher costs to install CHP rather

than replacing or retrofitting the system

boilers. Most building owners want to

avoid making major capital improve-

ments as they represent a lost oppor-

tunity cost for alternative investments.

Building owners also get deterred by the

uncertain risks and costs associated with

power production and performance.

These risks, along with the necessity of

deploying the incremental capital costs

of CHP, can be avoided by entering into

an Energy Services Agreement (ESA)

with a third party developer who will

agree to design, build, finance, own or

lease, and operate the system for a speci-

fied term. The building owner will then

acquire the asset at the end of the term

at an agreed-upon price.

A third party project finance arrangement typically encompasses the following:

� Developer agrees to design, engineer, permit, finance, build, own (or lease) and operate the CHP system

for a specified term. The developer takes on the risk of construction cost overruns, delays, forced outages

and system performance.

� Developer and owner agree on a price at which electricity and heating/cooling will be sold to the build-

ing. Operating and maintenance services are often included in the price. The price will be negotiated at

a discount or provide a guaranteed savings to the annual energy costs (heating/cooling, fuel and elec-

tricity) the building otherwise would expend. The contract would include penalties for non- or under-

performance by the system.

� The developer takes on the financing obligations, which is done on an “off-balance sheet” basis to the

building. The developer also provides insurance to cover construction and performance risks. Energy

payments made to the developer begin only once the CHP system is in commercial operation.

In addition to increasing net operat-

ing income using the above off-balance

sheet arrangement, the building owner

or asset manager obtains a predict-

able long-term operating budget and

increases its energy security. The incre-

mental value associated with mitigating

or avoiding power supply disruption in

areas subject to frequent utility outages

(e.g., Hurricanes Katrina and Sandy), can-

not be over-estimated.

A third party ownership and operation arrangement also can provide the building owner with the following additional benefits:

� Decreased property, casualty, and disaster recovery insurance costs

� Increased balance sheet and debt capacity

� LEED points for up to 50% energy cost reduction over baseline

� More competitive rental space due to reduced tenant costs

� Increased building sustainability and reduced carbon footprint

� Potential additional operating revenues by selling demand response and other energy products into the

regional power pool

Special thanks to Craig Gontkovic, CEO of Grid Energy Services, LLC., for his contribution to this article. GES advises companies on

integrating distributed energy systems into buildings on a turn-key, off-balance sheet basis.

email: [email protected]; 917-273-2360

19

FEdErAL rEPortInterview with 38 North SolutionsMajor federal energy legislation is under serious consideration for the first time in more than five years. At the same time, federal clean energy tax credits are poised to expire, with slim prospects in the Republican-controlled Congress. EPA is expected to release its Clean Power Plan regulating utility carbon emissions later this summer, and the Supreme Court will hear arguments on a hugely important FERC demand response order.

In early June the EDGE Advisory editors spoke with Katherine Hamilton and Jeffrey

Cramer of 38 North Solutions to get an update on policy developments in Washing-

ton and the states.

EDGE: The Senate Energy and Natural

Resources Committee is working on major

proposed energy legislation, with dozens of

individual bills under consideration. What

bills are you following and how do you see

prospects generally?

KH: We are tracking a total of 112 bills

that have been introduced in Senate En-

ergy and Natural Resources. The Com-

mittee leadership wants this to be a very

bipartisan process. They have held hear-

ings on infrastructure, energy efficiency,

supply, and accountability. Within those

categories, we have seen proposals for

distributed generation and a national en-

ergy storage goal. It looks like provisions

that might have some consensus include

transmission siting, a few infrastructure

issues, and energy efficiency. There is

strong interest in energy efficiency in

schools and non-profits, as well as smart

grid, distributed energy and energy stor-

age grant programs. I think it is likely

there will be authorization language for

these programs. Some of the DOE Qua-

drennial Energy Review recommenda-

tions also have broad agreement. An-

other set of proposals that has spurred

debate is around PURPA reform. EPACT

in 2005 and EISA in 2007 modified Sec-

tion 111(d) of PURPA to include states

“must consider” language. The “must

consider” list may be expanded to include

distributed generation, energy storage,

and other new technologies. Chairman

Murkowski has said we have to deal with

distributed generation in some way so

perhaps there is a path forward for these

distributed generation ideas.

EDGE: What do you expect for timing on

energy legislation on the Hill?

KH: The Senate will probably try to pull

everything together before the August

recess if it looks like they can get floor

time early in the fall. They are holding

four mark-ups in July to determine which

bills will make it into the final package.

Once a bill gets to the floor, presumably

in the fall, all bets are off. In an open

amendment process, we could see “poi-

son pills”—like curbing the EPA’s Clean

Power Plan—that could stymy passage

of a final bill. The House is also consider-

ing energy legislation on a parallel track.

Their bill looks different from the Sen-

ate version and has had a less expansive

stakeholder and Member process, but I

think we are going to see some overlap,

including potentially PURPA tweaks, in-

novation programs, and energy efficien-

cy provisions. The House will also try to

finish up and pass their bill before the

August recess. A bill can pass the House,

of course, without bipartisan consensus.

If final bills make it through both Cham-

bers, there will still need to be a confer-

ence to resolve differences before send-

ing a final package to the President.

EDGE: There has been a lot of discussion

about jurisdictional issues relating to dis-

tributed energy resources, particularly the

division of authority between states and the

FERC. Do you see Congress addressing this

topic?

KH: This is a very important issue. While

bulk power policy falls under the Federal

Power Act, I don’t see any opening up of

that legislation. The proposed PURPA

amendments can have an impact by

asking that states consider distributed

generation in their planning processes.

In the end, I think the states are going

to have a greater impact on deployment

of distributed generation resources, re-

gardless of Congressional action.


EDGE: There is increasing concern regard-

ing the prospects of Congress extending the

ITC and PTC clean energy tax incentives.

Are you seeing scenarios for extenders get-

ting passed in this Congress?

KH: Keep in mind that there are other

tax incentives beyond clean energy that

expired at the end of 2014 and need to

be extended. We believe there will be a

push on this front in the early fall. In July,

Senate Finance may mark up an extend-

ers bill similar to the EXPIRE Act from

2014. We would expect the wind PTC/

ITC to be included in that package, espe-

cially given the level of support from key

Senators in the Midwest and West. Con-

gress does not want to have to deal with

tax issues during an election cycle, so

perhaps the solar credits set to expire in

2016 could get some air time during the

extenders debate. The hope of course is

that the extenders package will not only

be retroactive to January 1, 2015, but

at a minimum go forward to the end of

2016.

EDGE: The Supreme Court has decided that

it will review the D.C. Court of Appeals de-

cision overturning FERC Order 745 on de-

mand response. What are the implications

of this case for distributed energy providers?

KH: This is shaping up to be a very im-

portant case. FERC Order 745 was very

narrowly defined: it only applies to de-

mand response in the energy market.

The energy market represents about

5% of demand response; the rest is in

the capacity market. But the way the

circuit court decision was written could

be interpreted to include any distribu-

tion resource participating in the entire

bulk power market. In fact, immediately

after the circuit court handed down its

decision, FirstEnergy filed a complaint at

FERC stating that the decision would im-

pact energy and capacity markets for de-

mand response and potentially other dis-

tribution side resources. Generators are

particularly at risk from distributed gen-

eration resources operating as flexible

capacity in the wholesale markets and

potentially displacing traditional gener-

ating resources. The Supreme Court has

decided to hear this case in its next ses-

sion, starting in October. If Order 745

is upheld, the markets should continue

to operate as is. If not, there will be a

great deal of upheaval of state demand

response programs (many of which are

monetized by bidding into the energy

market) and potentially in the capacity

markets as well. This is really a matter

of sound public policy, but we don’t know

how the Court will go. The Solicitor Gen-

21

eral has a strong case to make for FERC

and the federal government; we think it

warrants overturn of the circuit court

decision. Consumer groups, environ-

mental organizations, demand response

providers, and several states are all fil-

ing amicus briefs that should bolster the

case as well.

EDGE: EPA is expected to release its Clean

Power Plan final rule by August, requiring

states to implement plans to reduce carbon

emissions from power plants. Are you an-

ticipating any significant changes from the

approach taken in the proposed rule issued

in mid-2014, and what progress are you

seeing at the state level on preparing imple-

mentation plans?

KH: EPA received millions

of comments, with input and

information from many indi-

viduals, groups, and compa-

nies. I think those will be taken

into consideration and some

tweaks will be made to the final

rule, although we are hearing

that the overall goals will not

change. Hopefully, there will

be modifications to the “building block”

definitions – the types of actions that will

be available to states to achieve green-

house gas reductions. For example, I am

hopeful EPA will allow for energy stor-

age and other types of distributed en-

ergy generation to participate in a more

holistic way rather than be limited to re-

ductions on the demand side. Overall, I

think the rule will present an enormous

economic opportunity for clean energy

as well as consumers. EPA may be willing

to give additional flexibility to genera-

tors and states, but the trend will be to

develop cleaner resources. EPA may rec-

ommend alternatives and provide addi-

tional tools that will be helpful to states

as they start putting together their im-

plementation plans. I also think we will

see more focus on regional approaches

and guidance on how those can be exe-

cuted. What do you think about the state

implementation planning Jeff?

JC: There are a lot of factors the states

are considering. A number of states

are out on the front lines – staking out

leadership positions – in preparing state

implementation plans. Several regional

groups are working together, coalescing

their energy and environment officers to

think about what a mass state approach

and regional approach would look like.

This approach is very appealing given the

efficiencies that can be created. These

efforts are creating a de facto market,

even in advance of the final Clean Power

Plan rule. A number of states are in po-

sition to meet their CPP targets based

on current renewable portfolio stan-

dards and expected coal plant closures.

An important question is how EPA will

deal with early action credits. Progres-

sive utilities and developers have really

pushed that concept so EPA may very

well develop a path for early action. If

states are seriously considering the mass

state approach, you’re going to start to

see things happening very quickly.

KH: Senate Majority leader Mitch Mc-

Connell has said point blank states

should ignore EPA, but we know there

are quiet conversations about compli-

ance happening even in the states who

are suing the EPA.

JC: In talking with the stakeholders I

think the most positive sign is that utili-

ties are actively considering the CPP in

their projections and resource planning.

The CPP has jumpstarted the conver-

sation no matter what legal battles lie

ahead. I think just by looking at what

utilities are thinking about, regardless

of what governors are saying in certain

states, you can see what the plans will

look like and the signs are good for clean

energy.

EDGE: Last question: In the past

few years we’ve seen various bat-

tle grounds involving opposition

or repeal of state RPS’s or efforts

made in public service commis-

sion proceedings by utilities to

impose additional charges. Are

there any particular states or

proceedings that you are looking

at right now that you see as par-

ticularly interesting?

JC: I think we are seeing more educated

stakeholders and more organized groups

in support of distributed energy resourc-

es in states working together to inter-

vene, whether in rate cases or resource

planning. The move is to be proactive

rather than reactive. We are seeing new

grassroots efforts such as in Mississippi

to allow for net metering and intercon-

nection rules.

KH: Yes, I think the Southeast is about to

open up and create new markets for so-

lar and other renewables.

EDGE: Thanks to both of you. We will look

forward to catching up later in the year

on these and other energy policy develop-

ments.


GLoBAL trEnds in tHE distriButEd EnErGY trAnsitionThe worldwide transition towards distributed energy continues to accelerate. A number of recent an-nouncements and developments signal further rapid transformation ahead.

The role for utilitiesE.ON, Europe’s largest energy utility, is spinning off its conven-

tional energy assets. E.ON will be building its business around

clean energy and distributed generation going forward. Ger-

many has passed the point where renewables are the single

largest source of electricity generation. E.ON concluded that

its future business opportunities are in renewables, distributed

resources, energy efficiency and information services technolo-

gies. This move is likely to be a harbinger as other European

utilities are now considering similar strategies. The dynamic is

taking hold in the U.S. as well, as certain utilities such as NRG

Energy, Inc. are building their business around renewables and

distributed generation, and states such as New York are actively

moving towards new utility business models focused on distri-

bution. Can the stodgy utility sector be agents for change? Mar-

ket forces may leave them no choice.

Mining sector and distributed generationGlobal mining operations are energy intensive. For example,

South Africa’s Department of Minerals and Energy estimates

that the mining industry uses 6% of all the energy consumed

in South Africa. In Brazil, the largest single energy consumer is

mining giant Vale, which accounts for around 4% of all energy

used in the country.

Switching to distributed generation offers major potential economic benefits for mines, including:

� Lower aggregate long term fuel and electricity costs for operations and minerals processing.

� Reduced price volatility as compared to diesel fuel.

� Greater reliability and/or enhanced grid integration.

� Reduction in carbon emissions and resulting access to carbon reduction credits and government

incentives.

� Reduced risk of power loss from supply disruptions.

A key to unlocking these benefits is finance. Historically mining

companies have viewed energy cost as an operating expense,

and have hesitated to make capital expenditures for long term

generation. Now, mining executives, international financial in-

stitutions and NGOs such as the Carbon War Room are work-

ing to develop innovative financial mechanisms including third-

party ownership models. Given the upsides, expect to see major

developments in this area over the next few years.

23

The push for carbon pricing gains momentumIn the run-up to the global climate change treaty meetings in Paris this December, several developments are pointing to greater pros-

pects than ever for expanded carbon pricing regimes.

� In a letter on June 1, major European oil companies Shell, BP, Statoil, Eni, Total, and the BG Group advo-

cated before the United Nations Framework Convention on Climate Change that carbon pricing “should

be a key element” of an international climate change agreement. These oil companies join other major

sectors, including the insurance and securities industries, which are pushing for climate action based

largely on economic considerations.

� China has established a carbon fee and is moving forward with its plan for a national carbon market to be

launched in mid-2016. South Africa will make lawmakers vote on a carbon tax in 2016, while Chile has its

own scheduled for 2017. World Bank officials have described the “growing inevitability” of carbon pric-

ing at recent events, and estimate that current emissions trading market volume at $34 billion.

� Finally, we all saw the announcement by Pope Francis two weeks ago pressing the moral case for climate

action.

Will these developments help reach a tipping point for international action on carbon in Paris? All signs are for continued momentum

in that direction, and further consequent opportunities in the distributed energy sector.


GrEEn tEA coALition PusHinG rEnEWABLEs in tHE soutHEAst

The Green Tea Coalition is comprised

of the somewhat strange bedfellows

of conservatives, often, but not always

with links to the Tea Party Patriots, and

environmentalists. The movement has

been active in the Southeast, especially

Georgia where noted Tea Party leader

Debbie Dooley founded the non-profit

Conservatives for Energy Freedom. Tea

Party members of the Coalition cooper-

ate and sometimes work in concert with

traditional clean energy advocates. One

example is the joint efforts of the Sierra

Club and Tea Party Patriots to lobby the

Georgia Public Service Commission for

rule changes supporting solar energy.

While the members of the coalition co-

operate, their rhetoric varies. While

even casual observers can walk through

common Green talking points around cli-

mate change - management of resources

and environmental impact - the conser-

vative approach focusing on personal

liberty and security. For example, Geor-

gians for Solar Freedom speaks about

renewable energy in the context of na-

tional security, free market competition

and technological innovation.

The impact of conservative support has

been most visible in Georgia. Georgians

for Solar Freedom recently worked with

members of the Green Tea Coalition to

pass the Solar Power Free-Market Financ-

ing Act of 2015, which allowed for third-

party solar ownership in the state. Florida

is not far behind Georgia in authorizing

third-party ownership, and the potential

impact there could be even greater.

According to Scott Thomasson of Vote

Solar, Florida’s grassroots efforts are

“the real deal” and “the best and most

comprehensive” he has seen anywhere

in the nation. Mike Anthiel of the Flor-

ida Solar Energy Industry Association

(FlaSEIA) agrees, noting that Green Tea

efforts have directly led to a ballot initia-

tive process related to third-party own-

ership gaining steam there. Mr. Anthiel

believes the Coalition’s efforts to reverse

laws on the books under which solar

equipment is taxed as personal property

could be equally, if not more, impactful.

Solar development has focused on a few

main states in recent years, including

New York, Massachusetts, North Caro-

lina and California. However, as renew-

able portfolio standards (RPS) goals are

met and incentive programs sunset or

become less lucrative in some of the

more traditional solar states, project de-

velopers will necessarily be casting their

gazes toward parts of the map that are

typically colored in red as freedom of

energy choice becomes a rallying cry for

the right.

Other states where Green Tea-type co-

alitions could make an impact in the fu-

ture include the Carolinas, where efforts

have already been seen, and Louisiana, as

well as Midwestern states including Min-

nesota, Michigan and Kansas.

In an era that has been defined by partisanship, renewable energy advocates have recently proven that going green is one issue that can defy traditional party lines. What some are calling the “Green Tea Coalition” is gaining a seat at the table and forcing action in places where, until recently, the influence of utilities had blocked efforts to change the status quo.

25

rEPort FroM tHE stAtEsDistributed energy’s recent ascendance underscores a bevy of state policy and regulatory battles with significant implications for the nascent industry. Key states that have supported the growth of solar, California and Arizona in particular, are currently debating changes that could threaten deployments, particularly for rooftop residential and commercial installations. Other states are moving ahead with legislation opening up markets. Our friend Robert Rains, an Energy Analyst at Washington Analysis LLC, contributed to the following report:

On January 6, 2015, the administration of former Governor Deval Patrick solidified

Massachusetts as a leader in the residential solar energy market by announcing its fi-

nal design for the Mass Solar Loan Program. Commencing Spring 2015, the $30 million

residential loan program is helping homeowners finance the placement of solar panels on

their homes by working with banks and credit unions to lower loan rates and encourag-

ing lower income homeowners and/or those with lower credit scores to consider loans.

This program is an outgrowth of an earlier study, which determined homeowners’ overall

net benefits to be ten times greater with direct solar ownership (with loans) than third-

party ownership. Currently, according to SunRun, almost 60% of homeowners who have

gone solar chose a solar lease, rather than buying the panels. In the solar lease model,

SunRun and competitors typically provide the homeowner with the use of the solar sys-

tem and offer a Power Purchase Agreement (PPA), which locks in a long-term rate for

electricity generated by the system. Additionally, these developer entities assist with

residential installations for little customer money down, and then service the system

over its useful life, eliminating a large part of the hassle to the homeowner. However,

in exchange, the homeowner signs over to the developer their Solar Renewable Energy

Credits (SRECs) and other possible tax incentives (e.g. the Investment Tax Credit or ITC)

or rebates. In addition, SunRun, as the owner of the solar facility, benefits from net me-

tering policies instead of the customer.

This new solar loan program may change the paradigm, giving solar customers greater

control over their panels and the ability to directly monetize credits and other ownership

Connecticut

Northeast

Last month, the Connecticut State Senate approved H.B. 6838, which will expand the

state’s residential solar program and its energy goals, resulting in 300 megawatts of so-

lar installations on over 40,000 homes. The new residential solar incentive model was

proposed by Gov. Dannel Malloy in February as a way to attract more than $1 billion in

private investment in solar PV in the state.

Massachusetts


incentives. The goals of this program include increasing accessibility for all parties involved

(i.e. customers, lenders, and installers), creating an affordable solution that enables middle-

income homeowner participation, assisting smaller installers in securing financing for their

customers, and increasing competition in the residential solar market. If the program is

successful, a trend toward localization of solar loans could be expected to emerge in other

pioneering states, thus challenging the status quo of PPAs and solar leases.

Legislation to codify indications of support for 1,600 megawatts of solar by 2020 from

Massachusetts Energy and Environment Secretary Matt Beaton remains unlikely. In-

stead, we expect the Democratic-controlled legislature to advance another measure to

slightly raise the state’s net metering participation cap, a small positive for rooftop firms

already in the state.

New HampshireEarlier this year, the New Hampshire House of Representatives Science, Technology and

Energy Committee voted 18-2 to not recommend a bill (S.B. 117) to the full House that

would have removed barriers to utility ownership of rooftop solar. The action effectively

kills the bill, SB 117, which passed the Senate in March.

According to the publication Utility Dive the Committee chose to postpone a decision on

allowing power distribution companies to own rooftop solar because Eversource Energy

is currently completing divesture of generating facilities as required of New Hampshire

utilities under deregulation.

New YorkThe Reforming Energy Vision (REV) docket underway in the New York Public Service

Commission (PSC) forecasts the gradual creation of a retail-side distributed resources

market with opportunities for solar, wind, and energy storage. For now, the proposal ex-

cludes Con Edison and National Grid from ownership of these resources, but we expect

that to be modified before implementation begins sometime in late-2016 or later. A cost

benefit analysis from the PSC is expected to be released in early-June. Implementation

plans by the state’s electric utilities are due December 15, but the build out for REV will

likely stretch beyond 2017.

VermontLast month, the Vermont legislature created the state’s first renewable energy stan-

dards for electric utilities. The legislature passed a renewable portfolio standard (H.B.

40) that sets requirements for generating more energy from renewable sources, in-

cluding community-scale renewables. In particular, it requires utilities to get 55% of

their electricity from renewables by 2017 and 75% by 2032. The bill also created an

innovative program that requires utilities to achieve reductions in energy use through

efficiency measures and other programs. The Vermont House of Representatives

passed H.B. 40 on March 10, and the Senate approved an amended version on May 15.

Governor Peter Shumlin (D) signed the bill on June 11th.

27

SoutheastFlorida

Historically, Florida has been known as a difficult state for solar policy and we see little

to change this perception in the near term. The five-member Public Service Commis-

sion (PSC) is currently accepting comments related to “enhancing development” of so-

lar energy until June 23, 2015, forecasting a long-awaited PSC workshop for sometime

in July 2015. The workshop is likely to lay the groundwork for a reduction in solar ben-

efits that should be sought by Florida Power and Light as part of its next rate case. PSC

approval is likely, despite some expected backlash from ratepayers.

Florida solar groups have gathered enough signatures to start the process of amend-

ing the state’s constitution by referendum in 2016 to allow third-party power purchas-

ing agreements (PPAs) to unleash rooftop solar firms upon the state. Verification by

the Florida Supreme Court for this initiative is likely by October and supporters of this

amendment will then have to get roughly 600,000 more signatures on file by February

1, 2016 in order to be included on the ballot. It remains unclear if this initiative will be

successful as Florida Power and Light will likely mount a formidable campaign against it.

GeorgiaDespite lacking strong policy incentives such as a Renewable Portfolio Standard (RPS),

Georgia ranked 7th among the U.S. states in 2013 in new solar installations, attracting

$326.2 million in private investment in the sector, a 1,025 percent increase over 2012,

the largest gain of any state in that year. In lieu of mandatory standards such as an RPS,

Georgia has relied largely on voluntary clean energy programs, which are expected to

bring nearly 900 MW in renewables online by the end of 2016.

Solar markets in Georgia appear poised for additional growth following recent legisla-

tive activity. On March 27, the Georgia legislature passed the Solar Power Free-Market

Financing Act of 2015. The new law opens up third-party ownership of leased rooftop

solar projects up to a maximum of 10 kW generation capacity. In addition, the bill permits

third-party ownership of commercial solar energy installations, up to a limit of 125 per-

cent of the customer’s actual or expected annual peak energy demand. Georgia Gover-

nor Nathan Deal (R) signed the bill in May. Net metering policy reform to support greater

solar adoption seems unlikely near term, but commercial and utility scale opportunities

will likely continue.

The state’s largest utility, Southern Company subsidiary Georgia Power Co., has been re-

cruiting private sector participants through its Advanced Solar Initiative. Additionally,

the utility is working with the U.S. Army Energy Initiatives Task Force to build, own, and

operate 90 MW of solar power across three Army bases, which will, when operational,

cover an estimated 18% of the energy used by the Army in Georgia. Another potential

opportunity is presented by power sales in out-of-state markets, with a study by Arizona

State University finding Georgia to be one of the top three states that could benefit from

cross-border sales. We note that Georgia Power announced the purchase of two solar

projects totaling 99 MW of solar in late-February from Tradewind Energy, Inc.


North CarolinaThe North Carolina Utilities Commission (the Commission) recently entered an order

in its biennial rate proceeding rejecting requests by Duke Energy and other utilities

seeking to alter standard contract terms that are vitally important to solar developers

and investors in North Carolina.

North Carolina has been a booming market for solar over the last few years, currently

ranking third in the nation for energy investment. In February of 2014, Duke Energy

issued an RFP, which ultimately committed the utility to purchase $500 million of in-

dependent distributed energy in North Carolina. Much of the past success (and fu-

ture prospects for investment) are founded on the Commission’s standardize contract

terms and rates for power purchase agreements, which have provided certainty of eco-

nomic returns over 15 year time horizons.

But shortly after issuing its 2014 RFP, Duke and other NC utilities sought Commission

rulings that would reduce the standard PPA term from 15 down to 10 years, and re-

duce the eligibility from the current 5 megawatt project ceiling down to 100 kilowatts.

Fortunately for solar developers and investors, the Commission rejected Duke’s argu-

ments, finding that the current standard contact term of 15 years and availability to

projects up to 5 MW are well supported and appropriate.

Like Florida, North Carolina prohibits third-party ownership which has prevented rooftop

firms from meaningfully entering the state, but commercial- and utility-scale solar oppor-

tunities have abounded thanks to the 35% (and $2.5 million maximum) state tax credit that

expires YE 2016. While this credit is scheduled to be eliminated in 2017, projects 65 mega-

watts (MW) and smaller that are 80% complete, and 65 MW+ that are 50% complete, may

also qualify. Gov. Pat McCrory (R) has indicated he will not support any additional exten-

sions for this credit and the legislature is unlikely to pass another extension.

A proposal in the legislature (HB 332) would alter the state’s “standard offer” law from

a 5 MW over 15 years “standard offer” contract to just 100 kilowatts, most likely sig-

nificantly reducing solar deployments for the Tar Heel state because of its prohibition

of third-party ownership. A separate bill would establish third-party ownership, but

passage is uncertain. Furthermore, HB 332 would also freeze the state’s renewable

electricity standards rather than fully build out to 12.5% by 2021. The legislature is in

session, most likely, until August.

South CarolinaDespite average sunshine hours ranging from 173 in winter months to 291 during the

summer; in 2014, South Carolina only installed 1 megawatt (MW) of solar electric ca-

pacity, ranking it 33rd nationally. However, South Carolina did pass meaningful legisla-

tion in 2014, the Distributed Energy Resources Act, which called for utilities to estab-

lish distributed energy resources programs, enabled third-party leasing, and updated

the state’s net metering program. This enactment signals that legislators in the state’s

capital of Columbia are ready to bring the state more in step with the solar movement,

and open opportunities for investment and development.

29

Earlier this year, the South Carolina Public Services Commission approved a settle-

ment agreement between utilities and clean energy groups, which ensures that resi-

dential and commercial customers will receive full retail credit for over-generation on a

first-come, first-serve basis up to 2% of the utility’s peak capacity for the last five years.

The deal is being heralded as a critical step toward implementing the Distributed En-

ergy Resources Act. Duke Energy Carolinas and South Carolina Electric & Gas, which

both supported the deal, have committed millions of dollars to install residential and

commercial solar in the state.

West VirginiaWest Virginia Governor Earl Ray Tomblin recently signed into law a controversial net

metering bill (H.B. 2201) that limits net metering from solar power generation to 3% of

a utility’s aggregate customer peak demand, with 0.5% coming from residential custom-

ers. The bill also calls for the Public Service Commission to study the state’s net energy

metering policy rules to ensure that net metering does not cause a cost shift from solar

owners to non-solar owners.

VirginiaWhile Virginia has not historically offered robust clean energy incentives and programs,

Governor Terry McAuliffe appears determined to reverse the trend. On January 16,

2015, the Governor’s office released a request for information (RFI) seeking data on

potential public-private partnerships (P3s) for solar energy development in and around

state owned property. The RFI is directed towards experienced individuals, firms, teams,

and organizations that can help in development, financing, design, or building of P3 solar

projects above 100kW. The recent actions by Dominion Power and Governor McAuliffe

support the Governor’s statement that “Virginia is serious about enhancing its solar en-

ergy industry.” Among the challenges to development is Virginia’s voluntary Renewable

Portfolio Standard (RPS), as opposed to the mandatory structure successfully adopted by

twenty-nine states. Another obstacle noted is the lack of state tax incentives for private

developers.

MidwestIllinois

The Illinois legislature recently introduced H.B. 2607 and companion bill S.B. 1485, which

would strengthen the state’s current renewable portfolio standard and remove caps on

energy efficiency investments. The bill would increase energy efficiency standards from

13% to 20% by 2025 and renewable energy standards from 25% to 35% by 2030. The

bills also authorize the Illinois Environmental Protection Agency (IEPA) to establish a

program where the agency could sell carbon allowances at an auction and invest the pro-

ceeds, primarily in energy efficiency and renewables.


MichiganIn April, Michigan Gov. Rick Snyder (R) laid out a broad energy strategy to increase re-

newable energy generation and energy efficiency in the state. To help implement the

plan and develop the required energy policies and programs, the Michigan Agency of En-

ergy was created and opened last month. Michigan has a current target of 10 percent

renewable energy generation by 2022. The governor’s plan calls for retiring many of the

state’s aging coal-fired power plants to reduce the state’s reliance on coal and to help the

state be ready to adapt to energy challenges in the coming years.

WestArizona

In 2013, the Arizona Public Service (APS) sought to impose major charges on distributed

generation customers, but was largely rebuffed by the Arizona Corporation Commission

(ACC). APS requested a monthly charge for net-metering customers of $8 per kilowatt

of installed capacity for grid connectivity, a charge that could have exceeded $50 month-

ly on average. A compromise was approved by the ACC, authorizing a “connection fee”

of $0.70 per kilowatt of installed capacity per month for net-metered customers, about

$5 a month based on average usage. This result was generally viewed as averting a major

threat to distributed generation deployment in the APS service territory.

In February 2015, however, Salt River Project (SRP), the retail electric utility for Phoenix,

approved a pricing plan that adds fee of about $50 per month to all leased and owned

solar systems through a higher fixed service charge and demand charges.

SRP claims the new fees are needed to ensure solar customers pay their fair share for

their use of the electrical grid, and to support maintenance and upgrades on the network.

According to Credit Suisse, the $50 per month charge makes the economics of solar in

SRP’s area “effectively non-viable.”

In response, SolarCity filed a lawsuit in federal court in Arizona, asking the court to stop

SRP’s allegedly anti-competitive behavior. SolarCity says that SRP has “sabotaged the

ability of Arizona consumers to make this choice if they happen to live in SRP territory.

We can already see the intended effects: After the effective date of SRP’s new plan (De-

cember 8 of last year), applications for rooftop solar in SRP territory fell by 96%.” Solar-

City contends that the fee would jeopardize the more than 9,000 solar jobs in Arizona.

As an alternate strategy, in mid-2014 APS sought regulatory approval of its proposal

to install solar panels at no cost to the homeowners. The program, called “AZ Sun DG”

would install 3,000 residential 4-8kW solar systems. APS would effectively be leasing

consumers’ rooftops for a $30 a month savings on their bill.

In late December, the ACC voted to approve APS’s request, although with certain restric-

tions and conditions. The ACC approved a similar type of program proposed by Tucson

31

Electric Power Company. With these decisions, Arizona utilities may increasingly seek to

act as active participants in the solar and distributed generation markets.

Despite the growth in solar for the state, we view Arizona as the most challenging mar-

ket for rooftop solar providers in 2015 and beyond. First, implementation of a statewide

property tax for leased rooftop systems, the overwhelming consumer preference in Ar-

izona, remains likely this October and will add $12-$20 per month for residential and

commercial systems. Second, the five-member Arizona Corporation Commission will

likely approve higher fixed fees for new rooftop solar customers YE 2015. If approved,

the Arizona Public Service would raise fixed fees to $3 per kilowatt (kW) per month (from

$0.70 per kW), which would likely chill residential rooftop adoptions ahead of the next

rate case to be decided in 2016. Finally, while SolarCity is challenging both the property

tax and the $50 monthly net metering fixed fees that were recently adopted by munici-

pality SRP, the outlook for these cases remains uncertain

CaliforniaCalifornia Public Utility Commissioner Mike Florio recently proposed a collapse of

the state’s current four-tier retail electric rates into 3 tiers and setting a 77% differ-

ence between the highest electric consumption and the lowest electric consumption,

a positive for rooftop solar firms to be implemented in late-2015 to 2018. Compared

to the proposed decision by California Public Utility Commission (CPUC) Administra-

tive Law Judges (ALJ) issued in April, the proposal is favorable. Furthermore, under

Florio’s proposal, California would establish a baseline retail rate, a credit for the first

300 kilowatt-hours, and then an excessive use charge. Florio’s proposal also contains

language rejecting the implementation of fixed charges for “cost shift” that would have

benefitted California’s “big three” investor-owned utilities. Finally, the state would also

move to default time of use (TOU) rates.

In contrast, the ALJ proposal released in April would collapse the state’s four tiers into

just two by 2019 with a difference between these remaining rates of just 20% due to

rate increases for the lower tiers. Fixed fees would be implemented in 2019 (up to $10)

and we would expect an even higher price due to legislative action before the transition

is completed. During the transition, there would be a minimum bill set at $10 per month.

A third proposal from CPUC president Michael Picker seems likely that would incor-

porate elements of both proposals, still a potential headwind for rooftop solar because

we believe fixed fees are likely after the transition. Instructive in this outlook is Picker’s

previous work at the Sacramento Municipal Utility District, where solar fixed fees are

$13 per month and rising to $20 in 2017. A vote on reforming the state’s tiered retail

electric rates could occur as early as June 26.

Work continues at the CPUC concerning a new net metering tariff that we expect to be

voted on by YE 2015 for implementation by July 2017, or when the state reaches 5,200

megawatts (MW) of rooftop solar, as mandated by law. A proposal in Q3 is likely. Some

reduction in benefits enjoyed by current customers is likely, as indicated by the CPUC

decision to grandfather current net metering benefits for customers that adopt ahead

of the new tariff for 20 years.


Finally, Democratic Governor Jerry Brown’s announcement of a goal of a 50% renew-

able electricity portfolio standard (RPS) for the state by 2030, a positive for utility and

commercial scale firms that will require legislation in order to apply to the “big three”

investor-owned-utilities. Measures supporting this goal have advanced in both cham-

bers of the state legislature and passage of something before adjournment in Septem-

ber seems likely. Absent a specific carve out for rooftop solar, this policy does little to

rebut a decline in net metering incentives that we maintain is likely by the CPUC. The

CPUC has authority to raise the RPS mandate to 50% on its own, but it would only ap-

ply to state municipalities and cooperatives.

ColoradoIn Colorado, deliberations continue over the value of rooftop solar that was severed

from a proceeding concerning Xcel’s compliance with the state’s renewable electricity

mandate. Comments were due to the three-member Public Utility Commission (PUC)

in late-May and we expect a decision by the PUC by YE 2015. Our base case is the

implementation of a minimum bill for all ratepayers that would likely require a 6-12

month rulemaking process before being finalized.

HawaiiGov. David Ige (D) recently signed a bill passed by the Democratic-led Hawaiian legis-

lature before adjournment in May which will transition the state to 100% renewable

electricity by 2045. The state’s high retail electric rates ($0.31 per kilowatt-hour) have

pushed many customers towards rooftop solar and the trend is sure to increase as the

new legislation is implemented. An additional bill (H.B. 1509) if passed into law, would

make Hawaii’s state university system the first in the U.S. to have 100 percent renew-

able energy as a goal, including generating all its own power by 2035.

NevadaNevada’s sizzling solar market is likely to face headwinds when a new net metering pol-

icy is adopted by YE 2015 by the Public Utility Commission (PUC). A bill to temporar-

ily extend the state’s current net metering tariff for part of 2015 was recently passed,

allowing 80 megawatts of additional residential rooftop solar while the PUC develops

the new tariff.

Coloring this proceeding will likely be NV Energy’s forthcoming “cost of service” study

for solar expected by the PUC later this summer. The makeup of the three-member

PUC will matter greatly to this proceeding. Specifically, Commissioner David Boyle

may support the creation of a separate “class” of ratepayers for rooftop solar that

would likely lead to the implementation of fixed fees or else a minimum bill. Meanwhile,

Commissioner Rebecca Wagner will likely depart from the PUC this August and her

replacement is unknown. Wagner is widely considered to be the strongest advocate

on the PUC for solar and her replacement will be closely watched by solar advocates.

33

New MexicoWhile it is tempting for solar advocates to cheer the rejection of proposed interconnec-

tion fees ($21-36 per month) for solar customers in PNM Resources’ last rate case by the

Public Regulation Commission (PRC), we note that PNM Resources is expected to re-file

a proposal by September 2015 and we expect it to make modifications to the intercon-

nection fees proposal that should pass muster with the PRC in a decision sometime in

late-Q1 or early Q2 2016.

The state’s 10% solar tax credit expires in 2017 and we expect an extension to be a topic

of debate for state lawmakers when they return in January 2016. Although Republican

Gov. Susana Martinez vetoed a measure that would have allowed New Mexico ratepay-

ers leasing rooftop solar to qualify for the 10% state tax credit on the basis of “unintend-

ed consequences,” we think that a compromise to extend the state tax credit is likely.

WashingtonEarlier this year, the Washington State Senate approved S.B. 5735 which provides large

utilities alternative ways to comply with the state’s renewable energy mandate. S.B.

5735 allows utilities to use any resource that reduces carbon to meet the mandate,

including electric-vehicle chargers, hydropower and battery storage technologies. Un-

der the current law, utilities are required to get 15% of their power from wind, solar,

geothermal, and certain woody biomass by 2020. The bill is currently working its way

through state House committees.


Merrill Kramer represents some of the most active and innovative players in the energy industry in project

development, project finance, energy regulation, litigation and enforcement matters. He handles complex liti-

gation and enforcement matters before the Federal Energy Regulatory Commission, state regulatory agen-

cies and the courts.

Tricia Mundy represents public and private companies in a broad range of general business and finance mat-

ters, including energy financing and acquisition matters. She specializes in solar development and acquisition

transactions.

Jeffrey Karp advises clients in renewable energy and energy efficiency matters, including infrastructure de-

velopment. He also represents clients in litigating and resolving disputes under a variety of federal and state

laws.

EDGE Advisory is a publication of the Energy Finance Practice of Sullivan & Worcester, LLP. It is edited by Jim Wrathall and Elias

Hinckley. Contributing authors are listed below. Special thanks and acknowledgments for additional contributions from Rob Rains

of Washington Analysis, LLC; David Sweet of the World Alliance for Decentralized Energy; and Morgan Gerard of S&W.

ABout tHE AutHors

In addition to heading S&W’s Energy Finance Practice, Elias Hinckley has been the leader of the alternative

energy practice for one of the world’s largest professional services firms as well as the clean energy and clean-

tech leader for two AmLaw 100 law firms. He also is a professor of international energy policy, a regular con-

tributor to several energy forums and frequent speaker on energy policy and finance.

Jim Wrathall, co-leader of S&W’s Energy Finance Practice, represents investors, developers and non-govern-

mental organizations in energy finance and acquisition transactions and policy matters. Prior to joining S&W

he had over two decades of experience with AmLaw 20 law firms, including 11 years as a partner with Wilm-

erHale LLP. He served as Senior Counsel with the U.S. Senate Committee on Environment and Public Works

from 2007 through 2011, handling clean energy and climate change legislation and oversight.

35

A co-founder of 38 North Solutions, Katherine Hamilton cut her teeth designing electric grids at a utility, per-

formed energy and water efficiency research at a national lab, then used her technology expertise working on

clean energy policy and leading trade associations that could move the needle on bioenergy, smart grid, stor-

age, and demand response. She now spends most of her time shaping federal and state energy, environment,

and tax policies, as well as engaging in regional energy markets.

Also a co-founder of 38 North Solutions, Jeff Cramer has spent the last five years working as a public policy

analyst and advocate on behalf of a variety of leading businesses and non profits across the clean energy value

chain. Previously, Jeff worked in the finance sector developing expert networks of thought leaders in emerg-

ing technologies for institutional investors. He now spends a great deal of time working on state policy for

distributed energy technologies.

Josh Sturtevant represents clients, including early stage companies and funds, in energy project development

and project finance transactions, policy and regulatory matters, and corporate development matters. He pre-

viously served as lead inside legal counsel and as a member of the management team with Distributed Sun, a

privately held Washington, D.C.–based renewable energy developer, investor, owner and operator. At Distrib-

uted Sun, Josh managed diligence and transaction closings and advised on corporate development activities.

Natalie Lederman represents public and private companies in a broad range of general business and finance

matters, including corporate formation, mergers and acquisitions, public and private offerings, and securities

law compliance.

Van Hilderbrand Jr. 's practice focuses on energy finance projects, regulatory compliance, environmental,

and permitting matters. Mr. Hilderbrand represents a diverse set of clients across energy sectors with project

development and project finance transactions.


distributed energyintelligence

For more on the topics discussed in this

issue of EDGE Advisory, along with con-

tinuing updates and perspectives on

market trends and policies, please regis-

ter for S&W's blog, The Energy Finance

Report: www.energyfinancereport.com

EDGE Finance Advisory | www.edgefinanceadvisory.com

About Sullivan & Worcester, LLP

S&W is a mid-sized full services law firm

with offices in Washington, D.C., New

York, Boston, and London. S&W’s En-

ergy Finance Practice designs solutions

for complex financing challenges, includ-

ing the integration of new technologies

and related financial innovation for the

power generation industry, as well as the

deployment and commercialization of

advanced energy technologies and dis-

tributed generation projects.

About 38 North Solutions

38 North Solutions is a boutique consult-

ing firm that provides a suite of business

strategy and public policy services to in-

novative businesses and organizations.

Based on our firm’s expertise and deep

experience in clean energy, entrepre-

neurship, environment, sustainability,

technology, and venture capital fields,

we help our clients navigate market and

policy challenges and opportunities.

About EDGE Advisory

EDGE Finance Advisory provides cur-

rent, actionable updates and intelli-

gence developers and investors in the

distributed energy space. Our news and

analysis covers markets trends, innova-

tive financing, federal and state policy

and regulatory developments, inter-

national issues, and predictions for the

future.

WADE, the World Alliance for Decentralized Energy, works to accelerate the world-

wide development of high efficiency cogeneration, onsite power and decentralized re-

newable energy systems that deliver substantial economic and environmental benefits.

WADE works with chapter organizations around the world, gaining market intelligence

and collaborating with local governments and businesses to advance decentralized

energy.

EDGE Distributed Energy Advisory Q2 2015

Documents

Transcript of EDGE Distributed Energy Advisory Q2 2015