Low-Impact Hydropower in Pennsylvania - Autos2050resource for small and micro hydropower (“microhydro”) projects. This potential is currently unrealized, with less than 1% of the

Low-Impact Hydropower in Pennsylvania

Financial Feasibility Assessment

Pennsylvania Environmental Council

September 2015

Prepared by:

Low Impact Hydropower in Pennsylvania: Financial Feasibility Assessment September 2015 Page 1

Table of Contents

Executive Summary …………………………………………………………………………………… Page 2

Introduction …………..…………………………………………………………………………………… Page 5

Scope of Work ………………..………………………………………………………………………………. Page 5

Methodology ………………………………………………………………..……………………….……… Page 6

Project Viability ……….…………………………..………………………………..……………….……… Page 6

Potential Development & Ownership Structures ………………………………………………. Page 11

Conclusions and Recommendations ……………………………………………………………….. Page 16

Appendices

Appendix A: Notes on Financial Methodology ………………………………………………. Page 18

Appendix B: Sample Hydropower Project A Financials …………………..………….... Page 19

Appendix C: Sample Hydropower Project B Financials ………………………………….. Page 21

Acknowledgments

Palo Alto Partners would like to thank Lindsay Baxter of the Pennsylvania Environmental

Council for her assistance with this project. In addition, the information provided by

Jack Ashton of the Municipal Authority of Westmoreland County and Dan Huffington of

Pennsylvania American Water on their respective micro hydropower projects was

extremely helpful.

Feasibility Assessment: The Business Case for Low-Impact Hydropower September 2015 Page 2

Executive Summary

Overview

Pennsylvania, with more miles of streams and rivers than nearly any other state, has a considerable

resource for small and micro hydropower (“microhydro”) projects. This potential is currently unrealized,

with less than 1% of the state’s electricity generated by hydropower.1 The Pennsylvania Environmental

Council (PEC) organized the Pennsylvania Hydropower Summit in 2011 to identify barriers that impede

greater use of this resource and to brainstorm potential solutions. This Summit and subsequent

stakeholder sessions identified a number of constraints which impact the viability of potential projects

including: 1) relatively low electricity rates, 2) insufficient financial incentives, 3) restrictive net metering

policies, 4) high infrastructure and installation costs, and 5) extended and difficult to predict public

approval timelines.

The Pennsylvania Environmental Council collaborated with numerous federal and state agencies, project

developers, and other stakeholders to create the recently released Hydroelectric Permitting Manual for

Pennsylvania. The Permitting Manual is an important resource for understanding and navigating the

permitting process. With the Permitting Manual in place, PEC turned its efforts to addressing the

financial barriers to projects and retained consultant Palo Alto Partners to evaluate these barriers.

The purpose of this assessment is to better understand the financial feasibility of low-impact

hydropower projects in Pennsylvania, as well as the different financing and ownership structures to

support development of this alternative energy source. The scope is primarily focused on microhydro

installations at water treatment systems, publicly-owned impoundments, and industrial processes.

While there is great opportunity at federally-owned dams on Pennsylvania’s rivers, many of these sites

are already under consideration by development companies. With a comprehensive understanding of

both permitting and financial viability issues, PEC can work with stakeholders to facilitate microhydro

project development.

Analysis

Installation costs and the savings resulting from avoided electricity purchases drive the economics of a

hydropower project. In Pennsylvania, electricity costs are relatively low when compared with the rest of

the nation and large consumers can secure even lower prices. Further, the state’s energy production

subsidy, through the Alternative Energy Portfolio Standards (AEPS), is generally not sufficient to

generate a reasonable financial return. As a result, most projects require low or subsidized installation

costs to receive a viable financial return on investment.

Based on electricity pricing of $.075 per kWh, including transmission and distribution charges, a

microhydro project would need to have installation costs of less than $4,500 per kW to have a payback

1 U.S. Energy Information Administration


period of less than ten years. The two completed microhydro projects we evaluated had installation

costs of at least twice this and were economically viable only through significant capital subsidies that

were available at the time. Given these market realities, potential microhydro projects that address

other needs such as redundant power or environmental sustainability are the best candidates for

project development.

Most of the potential microhydro opportunities involve owners or sponsors that have access to water

flow, either through a natural resource or industrial process. These owners are often reluctant to

undertake a hydropower project because it is outside of their core business or mission, and involves a

significant up-front capital expenditure. Part of Palo Alto Partners’ scope included evaluating different

development ownership structures to address this barrier. Correctly structuring the ownership and

development of a project is critical not only to initiating the project, but also to positioning it for

successful completion.

Public-private partnerships have a long track record of successfully funding infrastructure and real estate

projects and provide a model for structuring microhydro investments. These partnerships allow public

entities to transfer some of the risk to private investors that are willing to accept it in exchange for a

portion of the project’s revenue. Applying this structure to a hydropower project, the private sector

would take on development risk and the up-front financial obligation in exchange for sharing in the long-

term cash flow. This type of structure addresses project barriers in instances where the project sponsor

is risk averse or wishes to retain capital for its core operations.

Recommendations

The key recommendations of this analysis include:

1) Improve the underlying fundamentals via policy changes that provide appropriate financial

incentives – Investment tax credits or subsidies can reduce the effective capital cost of a project.

Hydropower generates less attention, and less favorable tax credit treatment, than other

renewable resources such as solar. On the renewable energy production side, the pricing for

Tier 1 Alternative Energy Credits is currently so low that the existing projects we reviewed did

not spend the time or expense to qualify. Higher market-based pricing for these credits would

increase the financial benefit of a hydropower project, and, coupled with investment credits or

subsidies, would reduce a project’s payback period.

2) Assist stakeholders as they evaluate project viability—Market-based financial returns are not

the only reason to undertake a microhydro project. Other potential reasons include need for a

redundant power source, sustainability goals, and positive public relations. Given that many

potential projects in Pennsylvania may not currently offer market-based financial returns, PEC

can work to identify opportunities and sponsors where there are other compelling reasons to

undertake microhydro projects.


3) Market different options for structuring hydropower projects that help mitigate risk to the

sponsor agency – Even small hydropower projects are complicated from a licensing and

development standpoint. These complications and the underlying capital expenditure

requirements can prevent potential projects from moving forward, even in circumstances where

the underlying business case is favorable. PEC can take a lead role working with existing

stakeholders to suggest how projects are structured. This involves bringing together public and

private sector interests to work together creatively. Certain project benefits, such as tax credits

or accelerated depreciation, may have value only to private sector partners and would

otherwise be lost in a transaction owned and developed by a municipal agency or other non-

taxable entity.


Introduction

While the size definitions for hydropower projects can vary greatly, for the purposes of this assessment,

we are primarily interested in small and microhydro projects of 500 kW or smaller. Many of the

potential projects in Pennsylvania fall into this category. The environmental impacts of a hydropower

project are site specific, and should not be generalized based on the amount of electricity a project

generates.

Hydropower projects that draw water from a natural environment and substantially alter the flow or

temperature of water that is returned to this environment can cause damage to the existing wildlife

habitat. Negative environmental impacts can occur regardless of the size of the associated

infrastructure or electric output from the project. Run-of-the-river projects allow water to pass at about

the same rate that the river is flowing, and tend to have low environmental impacts. In-pipe

hydropower projects utilize a water source that is already flowing through a pipe, typically for a water

treatment facility, and these projects also tend to have lower environmental impacts because they do

not disturb the natural environment. PEC is interested specifically in these types of projects that do not

have negative environmental impacts.

The permitting for a microhydro facility involves numerous federal and state agencies. The process is

detailed in PEC’s Hydroelectric Permitting Manual for Pennsylvania, and a key conclusion is that even

microhydro facilities using power exclusively behind the meter must follow this process. Although the

Federal Energy Regulatory Commission (FERC) has an exemption for certain hydropower facilities, that

exemption is not a complete waiver, but rather still requires a regulatory process, albeit a simpler one

than that for a license.

Scope of Work

The Scope of Work for the project includes the following elements:

Analysis of the financial viability of small, low-impact projects with a particular emphasis on

projects at publicly owned reservoirs and at water treatment works.

Identification of project parameters that are needed for economic viability.

Comparison of various ownership and development structures including: a) municipal ownership

and development, b) third-party developer, c) private owner and developer, and d) a public-

private partnership through a special purpose entity (SPE).


Methodology

This analysis provides a high-level framework for strategies to improve the economic viability of low-

impact microhydro projects. Data from existing local projects and feasibility studies were utilized.

These include completed projects by Municipal Authority of Westmoreland County (MAWC) at the

Beaver Run Reservoir and Pennsylvania American Water (PAW) at their Oneida Valley Water Treatment

Plant. Feasibility studies for projects in Ohiopyle, PA and New Canton, CT were also reviewed.

Budgets and operating pro formas were developed at conceptual, or pre-design, stage utilizing

estimated costs. Contingencies were factored in to account for potential cost increases during the

engineering and design stages. For the development of operating pro formas, estimated long-term

utility rates from the U.S. Energy Information Administration (EIA) were utilized. Operating costs were

estimated at 10% of revenue.

The budget and pro forma analysis generates a rough-size estimate of project economics and provides a

better understanding of both the cost and revenue parameters that a project will need to fall within to

be economically viable. Establishing economic viability parameters is important, as microhydro project

costs are difficult to generalize due to a number of site-specific factors. As projects that pass an initial

financial feasibility review move forward, costs will become more refined during the engineering and

design stage.

Structuring the financing and ownership of a microhydro project is often a challenge, even in cases

where the underlying economics of the project are viable. With municipal entities, up-front capital costs

may pose a significant barrier. We did not limit our analysis of potential project development and

ownership structures to ones that are currently operating in the hydropower field. There are models of

public-private partnerships that have been utilized for real estate and infrastructure development that

were evaluated for their applicability in developing hydropower projects.

Project Viability

Project Size

The Beaver Run Reservoir project analyzed for this study provides a good example of the type of

hydropower project that captures an existing water flow to produce electricity that is used on site. This

project involves diverting a portion of the mandated release from an existing reservoir into a twelve inch

diameter line that powers a turbine generator. The 30 kW turbine generator system is used behind the

meter to partially power the adjacent pumps that transfer raw water from the reservoir to the water

treatment plant. MAWC is recovering energy that otherwise would be lost, and recovering this energy

in an environmentally sustainable manner.


Project Constraints

Pennsylvania has 83,000 miles of streams and rivers, and even more controlled water flows from water

treatment plants and industrial processes, yet it generates less than 1% of the electricity currently used

in the state.2 PEC’s stakeholder sessions in 2013 identified a number of constraints which impact the

viability of potential projects including: 1) relatively low electricity rates, 2) insufficient financial

incentives, 3) restrictive net metering policies, 4) high infrastructure and installation costs, and 5)

extended and difficult to predict public approval timelines.

Electricity pricing for industrial users in Pennsylvania averages $.067 per kWh.3 This rate is significantly

lower than in west coast states such as California that generate a much higher percentage of electricity

from hydropower sources. Lower electricity rates result in longer project payback periods.

Tax and production credit programs designed to improve the financial viability of renewable energy

projects exist at both the federal and state government levels. Pennsylvania has Alternative Energy

Credits which are created when a facility produces a MWh of electricity from a qualified renewable

source. These credits are based on a tiered system with Tier 1 credits being more valuable than Tier 2

credits. If a hydropower project is certified by the Low Impact Hydropower Institute (LIHI) as low-

impact, it can qualify for Tier 1 credits. These credits can be sold or traded, and the most recent market

pricing for these credits was $9.78 per MWh, which does not generate much for a microhydro project

once the cost of certification and selling the credits are factored in.

The cost of certification from LIHI involves an initial intake fee, application review fee, annual fee, and a

recertification fee after five years. These fees are summarized in Table 1.

Table 1: Low Impact Hydropower Institute Certification Fees

Fee Type Fee Amount

Intake Review $950

Application Review Fee As estimated at intake + administrative overhead. For a micro project, can be between $2,500 and $5,000

Annual Fee Base rate: $0.0175 / MWh $1,000 minimum under 5 MWh

Recertification Fee (required in five or eight years after initial review)

75% of the initial Application Review Fee

Sources: Low Impact Hydropower Association website, conversation with Director Michael Sale on 8/17/15

These certification costs can be significant, particularly for microhydro projects. With the current value

of Tier 1 credits, it may take a project several years just to amortize the certification costs. The

2 Sources: U.S. Environmental Protection Agency and the U.S. Energy Information Administration

3 Source: U.S. Energy Information Administration


Executive Director of LIHI indicated that they are currently working on changes to the criteria that

should make it easier and less costly for microhydro projects to qualify.

Installation costs are site specific, and in many cases they are high relative to the economic benefits

generated. These installation costs must include the cost of the infrastructure to divert the water flow

and any electrical infrastructure required to connect the new power source to the facilities that it is

servicing. In the case of the PAW’s Oneida Valley project, infrastructure expenses ended up costing

more than anticipated and lengthened the project’s payback period.

Pennsylvania’s net metering rules allow a customer to sell electricity into the grid during times when on-

site production exceeds on site-demand. However, the Pennsylvania Public Utility Commission (PUC)

considers facilities that generate electricity in excess of 110% of their on-site needs to be commercial

generating entities, essentially putting a cap on the amount of electricity that can be produced on site,

regardless of potential. Additionally, net metering rules limit the distance allowed between the

generation system and the electricity load. For instance, if the optimal turbine location is in a pipe in the

reservoir, but the load is at a water treatment plant, the project may not qualify for net metering,

despite the fact that the entire infrastructure is owned by the same customer. Separate from the issue

of net metering, the greater the distance between the generation and the load, the more expensive the

project becomes due to the transportation of the electricity.

As detailed in PEC’s Hydroelectric Permitting Manual, the permitting process typically involves many

regulatory agencies. This may require the applicant to spend significant money without the certainty

that they will be successful getting the necessary permits. For both municipal entities and private

investors, the permitting timeline and process remain a challenge that can discourage investment in

new projects.

Financial Viability

To evaluate project viability we utilized a straight payback period that calculates the number of years it

takes for a project to recapture its initial investment. While other financial calculations such as net

present value or internal rate of return are often utilized, the straight payback period provides an

appropriate initial screen to determine a project’s viability. Each company or public agency may set

different targets for an acceptable payback period.

Municipal authorities and other public agencies typically like to see payback periods of less than seven

years. Most for-profit companies set payback periods of less than five years, as they generally have

higher costs of capital and therefore demand higher rates of return. Some of the companies and

municipal agencies interviewed for this project indicated a willingness to accept slightly longer payback

periods for projects, such as hydropower, that meet their established sustainability goals.


The payback period for a hydropower project is driven largely by two factors: 1) the total up-front cost

of the project, and 2) the net electricity cost saved. In Pennsylvania, installation costs tend to have a

higher degree of variability than electricity cost does. An example budget, operating pro forma, and

cash flow statement are included as Appendix B. To further quantify the relationship between key

project variables, Figure 2 summarizes how payback periods vary based on total installed kW cost and

net electricity savings rate.

Figure 2: Payback Period as a Function of Installed Costs and Electricity Savings Rates

Electricity Cost Straight Payback Period (in years) Savings per kWh Installed Cost Per kW $4,000 $6,000 $8,000 $10,000 $12,000 $14,000 $0.05 12.1 17.8 23.3 28.6 33.6 38.6 $0.06 10.2 15.0 19.7 24.2 28.6 32.8 $0.07 8.8 12.9 17.0 21.0 24.8 28.6 $0.08 7.7 11.4 15.0 18.5 21.9 25.3 $0.09 6.9 10.2 13.4 16.6 19.7 22.7 $0.10 6.2 9.2 12.1 15.0 17.8 20.6 $0.11 5.6 8.4 11.1 13.7 16.3 18.8 $0.12 5.2 7.7 10.2 12.6 15.0 17.3

Assumptions 1. Turbine is 50 kW. Runs 80% capacity. This accounts for time off-line and unused capacity.

2. 10% annual maintenance costs. 3. 0.7% annual cost escalation for electricity rates. Source: U.S. EIA

The portion of the chart that has payback periods of less than ten years are on projects that have

relatively low installation costs and relatively high electricity rates. As a benchmark, MAWC’s Beaver

Run Reservoir project had a total installation cost of $10,800 per kW and generated annual savings of

roughly $.08 per kWh. This project received a significant grant from the Pennsylvania Department of

Environmental Protection which effectively reduced the payback period from greater than fifteen years

to less than five years.

The Beaver Run Reservoir project highlights the economic challenge to many potential hydropower

projects—without subsidies that increase the value of production or reduce costs, the financial returns

are not sufficient to justify a sponsor’s investment. There are other compelling reasons that a sponsor

may undertake a hydropower project with longer payback periods including concerns about the

reliability of their existing power source, environmental benefits, and positive public relations. PAW’s

Oneida Valley project had sustainability benefits that allowed the company to accept a payback period

of more than five years.


To provide an example of how tax credits and incentives can improve the payback period of potential

projects, we prepared another financial model in Appendix C utilizing both capital and production

incentives. A broader reflection of how payback periods move against these two variables is shown in

Figure 3 that incorporates a 30% credit on the installation costs4 and calculates Alternative Energy

Credits at current market value.5

Figure 3: Payback Period Incorporating a 30% Investment Tax Credit and Alternative Energy Credits at

Market Value

Electricity Cost Straight Payback Period (in years) Savings per kWh Installed Cost Per kW $4,000 $6,000 $8,000 $10,000 $12,000 $14,000 $0.05 7.7 11.4 14.9 18.4 21.9 25.2 $0.06 6.6 9.8 12.9 15.9 18.9 21.9 $0.07 5.8 8.6 11.3 14.0 16.7 19.3 $0.08 5.2 7.7 10.1 12.5 14.9 17.3 $0.09 4.6 6.9 9.1 11.3 13.5 15.6 $0.10 4.2 6.3 8.3 10.3 12.3 14.3 $0.11 3.9 5.8 7.7 9.5 11.3 13.1 $0.12 3.6 5.3 7.1 8.8 10.5 12.2

Assumptions 1. Turbine is 50 kW. Runs at 80% capacity. This accounts for time off-line and unused capacity.

2. 10% annual maintenance costs. 3. 0.7% annual cost escalation for electricity rates. This data is from the U.S. EIA.

4. Alternative Energy Credits at $9.78 per MWh.

Combining tax credits on the cost of installation with the Alternative Energy Credits creates a larger pool

of economically viable projects. In this case, with installed pricing of $6,000 per kW and electricity

pricing at $.08 per kWh, a project would have less than an eight-year payback whereas without these

credits the payback period would be over ten years. This underscores the importance of policy changes

to improve the economics of projects, particularly in the current environment when direct grant

subsidies are less available.

The structuring of hydropower project development and ownership plays an important role in

addressing the needs of a project sponsor. Not only must the underlying fundamentals of a project be

viable, the project must be structured to reflect the risk and reward preferences of its sponsor. For

4 The Federal Investment Tax Credit is currently available at 30% for solar facilities.

5 Most recent published price by the Pennsylvania PUC


example, a project with an acceptable payback period may not be pursued if the sponsor does not have

available capital and is averse to taking on debt. A project’s development and ownership can be

structured to address these issues.

Development and Ownership Structures

Overview

The universe of potential development and ownership structures for hydropower projects reflects a

continuum rather than a few discrete options. On the one end of this continuum is a project that is

owned and developed by the property owner itself. The MAWC and PAW projects evaluated for this

study were developed using this structure. On the other end of the continuum is a project developed

and controlled, likely through a long-term lease, by a third-party private developer. Between these two

points, there are multiple ways to structure a project. A review of where each of these four options is

on the continuum is presented in Figure 4.

Figure 4: Simplified Development and Ownership Structure Continuum

With these four potential structures, most of the underlying economic fundamentals are the same. The

differences relate primarily to how the financial risks and rewards to a project’s stakeholders are divided

up. Some of PEC’s initial research on low-impact hydropower in Pennsylvania suggests that risk aversion

plays a role in keeping otherwise financially viable projects from being developed. This highlights the

importance of finding ways to structure projects in a way that aligns with the stakeholders’ particular

risk and reward preferences.

Municipal Ownership & Development

The least complicated way for a municipality or public works authority to structure a small hydropower

project is often to develop it on their own using the electricity generated to offset existing demand. In

Private

Development

& Control

Public-Private

Partnership

Turn-Key

Development

by Private

Developer for

Municipal

Owner

Municipal

Ownership &

Development

Municipally Owned & Controlled Privately Owned & Controlled


this scenario, the public entity typically hires the design, engineering, and contracting expertise for the

project. In some cases, depending on the level of existing staff expertise, some of these functions may

be completed by the agency itself.

An advantage of this structure is that third-party development costs are typically minimized, particularly

if the municipality or authority has the ability to do some of the design or construction work in house.

Public agencies also often have access to lower cost funds, such as tax-exempt bonds, than are available

on the private market. One potential disadvantage is that the agency will have to bear the up-front

capital cost and public agencies often shy away from taking on additional debt—particularly for a project

that is not central to its mission.

Third Party Turn-Key Development

In situations where an owner has no interest in acting as a developer, a third-party developer is often

sought that will oversee and manage the completion of the project for a fee. This arrangement usually

has the owner retain control of the property. The developer may finance the cost of the project during

construction and then sell the completed improvements back to the land owner or permit holder at

completion. This model is similar to the owner-as-developer model with the distinction being that the

third party consultant takes on development risk in the turn-key model rather than merely providing

professional services in a fee-for-service model.

The advantage to the turn-key development model is that the risk of cost overruns is typically assumed

by the developer. The model also leverages the expertise of a developer that navigates the approval

process and coordinates construction. The disadvantage to this model is that it can add cost to a

project, and the incremental cost may be enough to affect the feasibility of the project. Developer fees

can range based on the size and complexity of the project, but they typically run 10% to 20% of the

project’s total development cost.

Special Purpose Entity or Public-Private Partnership

Public-private partnerships (also called P3s) are commonly used for real estate and infrastructure

projects as a way to attract private capital to projects. In most instances, the public sector investment

pays for a portion of the project and captures a portion of the financial return. The remaining portion of

the future cash flows is structured to provide a market-based return for the private investment that is

leveraged. Often this is structured as some type of joint venture or special purpose entity (SPE) in which

both the public and private sector stakeholders have financial interests.

The best way to illustrate the way a creative public-private partnership works is through an example.

Pennsylvania has an innovative Transit Revitalization Investment District (TRID) law that functions

similar to a tax increment financing district. Funds are typically raised by pledging anticipated tax

revenues to pay for transit and other related infrastructure improvements that support private


development. These funds are then paid back over time from the increment of new real estate tax

revenue from construction within the district. In the case of a hydropower project, the future cash flows

are the savings from electricity costs as opposed to increased tax revenue yet in both cases these

provide the opportunity to leverage the up-front capital costs of a project.

The potential appeal of a public-private partnership is that it can be structured to meet the different risk

and reward profiles of the participants. For example, most municipal agencies are willing to accept a

lower return in exchange for a lower risk. Private capital will take on a greater level of risk in exchange

for a higher return. These different risk and reward profiles can be structured into a public-private

partnership by creating different categories of investments.

One interesting application of a TRID project provides an example of how different categories of

investments can be created to leverage additional private capital. For the East Liberty TRID, in addition

to bond funds, private foundations invested money into the financing structure. The payback was

structured so that the tax increment proceeds first went to service the bond debt. If additional tax

increment was available after the bond debt was serviced, the foundation investment received a

preferred return of up to 10%. Since the real estate market is appreciating in East Liberty, private capital

is willing to invest in this financial structure.

The potential for public-private partnerships is strongest in cases where net metering is possible and the

electricity prices are expected to appreciate rapidly. Although these conditions are not currently met in

Pennsylvania, there is still a role for private capital in microhydro projects. Even in cases where this

private capital is a small percentage of the overall capital stack, it can lessen the amount of municipal or

public financing needed for a project. A sample of this transaction structure is shown in Figure 5.


Figure 5: Hypothetical Public-Private Partnership Transaction Structure

At Closing

During Operations

The disadvantage of a public-private partnership structure is that it can be complex and, as a result, legal

and other transaction costs are higher than with other ownership structures. Care has to be taken in

these structures so that the risk and return parameters are reasonable and that public funding does not

unduly enrich private interests. These issues have been successfully addressed in other public-private

partnerships, and do not pose an insurmountable hurdle to most potential projects.

Private Ownership / Power Purchase Agreement

Some operating companies no longer wish to carry real estate on their financial statements so they

structure deals in which they sell real estate assets to private developers and enter into long-term

contracts to lease them back. A similar model is relevant for microhydro projects that will address the

concern many municipal agencies have of spending their own capital dollars. In this scenario a private

developer may own, or hold a long-term lease to utilize the water flow, and then sell the resulting

Newco Hydropower LLC

Private Investor

Pool – Provides

20% of capital

requirement

Subsidiary of Municipal Authority –

Provides 80% of capital requirement

through a bond issue.

Cash Flow from Operations

1st Priority – 3% Coupon

2nd Priority – 10% Preferred Return

3rd Priority – Residual Distribution

Bondholders

Private Investor Pool

80% to Subsidiary of Municipal

Authority

20% to Private Investor Pool


power back to the agency. In order to be financially viable, a long-term power purchase agreement

from the end user is typically necessary.6

The advantage of this model is that it can generate an economic benefit for the end user, a reliable

source of electricity at a fixed price, who can realize this benefit without an initial outlay of capital. The

model is very similar to how Energy Service Companies (ESCO) contract with facility owners for capital

improvements. The ESCO takes on the capital cost and guarantees a certain level of utility saving for the

end user. In this model, the owner and developer take on the performance risk but retain the upside of

generating additional savings.

The challenge with this model is that future projected electricity price escalations are modest. In an

environment where rate increases are modest and predictable, the incentive for a user to sign a long-

term power purchase agreement is often not compelling. From the developer side, the long-term

power price has to be sufficient to make the financial return appealing. In the current environment, the

most likely application of this model may be where a user is willing to pay a modest premium for power

generated on site from an environmentally friendly source. Another advantage of this structure is that

the private partner can make use of tax benefits that are not of value to a municipal authority or non-

profit owner.

A comparison of these four points along the development and ownership continuum is shown in Figure

6.

6 This is similar to a commercial real estate transaction where a long-term lease from a credit tenant allows the

landlord to finance the improvements.


Figure 6: Summary Comparison of Development & Ownership Structures

Structure Potential Advantages Potential Disadvantages Relative Control by Public or Municipal Entity

Relative Risk by Public or Municipal Entity

Municipal Ownership & Development

Relatively simple transaction structure.

Generally lower transaction costs.

May be outside a public entity’s mission and core competency.

Generally fewer options to leverage private capital

High Moderate

3rd

Party Turn-Key Development

Leverages development expertise.

Lowers development risk to the public entity.

Higher cost structure than a self-developed project.

Moderate Low

Public-Private Partnership

Provides the greatest flexibility in leveraging different capital sources.

Can be tailored to match the different risk and reward profiles of public and private entities.

Can be complicated and costly to structure.

Moderate Moderate

Private Ownership

Less risk to the public entity.

Generally public entity has no control over development or operations.

Works best in an environment with higher utility costs, limited applicability in Pennsylvania.

Low Low

Conclusions and Recommendations

There are two primary hurdles for a company or agency considering a microhyrdro project. First, the

project must demonstrate a reasonable business case. If the project passes that first step, the second

step is to determine if there is a way to finance and structure the project that makes sense for the

agency. This may involve another entity providing the capital and assuming some of the risk in exchange

for getting some of the underlying benefits of the project.

Market conditions in Pennsylvania are such that many potential projects do not have compelling rates of

return. Given current pricing for electricity and installation costs, most straight payback periods are in

excess of ten years. Both of the case study projects we looked at relied on grant funding in order to


reduce the payback periods to within an acceptable range. Most of these grant programs are no longer

available.

For hydropower projects that are economically feasible, municipal agencies may be averse to taking on

debt, and public-private partnerships structured for other types of projects provide a model for

allocating risks and rewards. Many public agencies will trade some of the potential economic benefits

for cost certainty and the elimination of development risk. The PAW’s Oneida Valley facility went over

the initial budget, and the cost to the agency could have been shifted to a developer in the turn-key or

power purchase transaction structure.

A summary of the recommendations is as follows:

1) Improve the underlying fundamentals via policy changes that provide appropriate financial

incentives – A combination of subsidies and credits on both the installation and production side

are necessary to make micro and in-pipe hydropower projects in Pennsylvania commercially

viable. On the production side, the current value of Pennsylvania’s Alternative Energy Credits

needs to be enhanced or supplemented to provide a more meaningful incentive. Revisiting how

low-impact microhydro qualifies for Tier 1 credits should also be explored, with the goal of

reducing the cost for a project to qualify. On the installation side, credits or direct subsidies that

effectively reduce a project’s installation costs are needed. The federal Investment Tax Credit

(ITC) provides a 30% investment credit, but hydropower is not currently one of the eligible

sources for this level of incentive.

2) Assist stakeholders as they evaluate project viability—While the focus of this analysis was on the

financial return for microhydro projects, there are often other important business

considerations for considering a project. These include having a redundant power source,

meeting sustainability objectives, and other business considerations that a sponsor is willing to

accept a longer pay back period for. In addition, business and agencies that have an existing

water flow that are considering infrastructure upgrades may be willing to incorporate a

microhydro project as part of a larger initiative. PEC can identify and work with businesses and

agencies to evaluate these projects, and suggest a development and ownership structure that

makes sense.

3) Market different options for structuring hydropower projects that help mitigate risk to the

sponsor agency – On the ownership continuum, the public-private partnership model and power

purchase agreements shift risk to the private sector while still pursuing many of the economic

and other benefits for the project sponsor. In many cases, additional time and expense to

structuring a project this way is a good long-term investment. PEC can help lead this

conversation, and bring public and private stakeholders into the discussion.


Appendix A: Notes on Financial Methodology

In order to show the difference that investment tax credits and production incentives make in a

project’s budget and pro forma, we present a scenario without these incentives in Appendix B and then

with these incentives in Appendix C. The other important project variables such as construction costs

and electricity rates are the same in both scenarios. The use of both investment tax credits and

production incentives has associated costs that have been factored into the project structure.

The project size involves the installation of a 50kW turbine. To calculate annual kWh we assume the

turbine runs at 80% of its potential year round. Average electricity pricing starts at $.085 and per kWh

and increases annually by 0.7%, a factor provided by the U.S. EIA. Operating and maintenance costs are

estimated at 10% of the value of the electricity saved. In order to trade the production credits, we have

incorporated initial certification costs, annual fees, and recertification costs that would be paid to the

Low Impact Hydropower Institute. These costs appear in Appendix C, and further explanation is

provided in Table 1 of the report.

Sample Hydropower Project A: No Investment or Production IncentivesSources & Uses of Funds

Sources Notes

Owner's Capital $528,000

Total $528,000

Uses Notes

Equipment & Construction $425,000 Turbine, generator, powerhouse, and electrical infrastructure

Design & Engineering $40,000

Legal & Permitting $5,000

Other Soft Costs $10,000

Project Contingency $48,000

Total $528,000

Assumptions

Project Size 50kW

Contingency % 10%

Appendix B

Sample Hydropower Project A: No Investment or Production IncentivesOperating Proforma & Cash Flow Summary

Operating Proforma

Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 20 Cumulative

Revenues

Value of Electricity Saved $29,992 $30,202 $30,414 $30,627 $30,841 $31,057 $31,274 $31,493 $34,243 $641,466

Total $29,992 $30,202 $30,414 $30,627 $30,841 $31,057 $31,274 $31,493 $34,243 $641,466

Expenses

Operating & Maintenance Costs $2,999 $3,020 $3,041 $3,063 $3,084 $3,106 $3,127 $3,149 $3,424 $64,147

Depreciation $17,600 $17,600 $17,600 $17,600 $17,600 $17,600 $17,600 $17,600 $17,600 $352,000

Total $20,599 $20,620 $20,641 $20,663 $20,684 $20,706 $20,727 $20,749 $21,024 $416,147

Net Revenues $9,393 $9,582 $9,772 $9,964 $10,157 $10,351 $10,547 $10,744 $13,219 $225,320

Cash Flow

Year 0 Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 20 Cumulative

Initial Capital Investment ($528,000) 0 ($528,000)

Net Revenue 0 $9,393 $9,582 $9,772 $9,964 $10,157 $10,351 $10,547 $10,744 $13,219 $225,320

Depreciation 0 $17,600 $17,600 $17,600 $17,600 $17,600 $17,600 $17,600 $17,600 $17,600 $352,000

Total ($528,000) $26,993 $27,182 $27,372 $27,564 $27,757 $27,951 $28,147 $28,344 $30,819 $49,320

Cumulative ($528,000) ($501,007) ($473,825) ($446,452) ($418,888) ($391,131) ($363,180) ($335,033) ($306,689) $49,320

Total Payback Period (in Years) 18.4

Assumptions Notes

Turbine Capacity (in kW) 50

Operating Percentage 80% To account for unused capacity and down time

MWh Generated 350.4

Initial Electricity Price Savings per kWh $0.085

Annual Electricity Cost Escalation 0.7% Source: U.S. EIA

Operating & Maintenance Costs 10% As a percentage of electricity cost savings

Depreciation Schedule (Years) 30 Assume straight line method

Appendix B

Sample Hydropower Project B: Enhanced Investment and Production IncentivesSources & Uses of Funds

Sources Notes

Owner's Capital $411,100

Tax Credit Equity $122,400

Total $533,500

Uses Notes

Equipment & Construction $425,000 Turbine, generator, powerhouse, and electrical infrastructure

Design & Engineering $40,000

Legal & Permitting $5,000

Other Soft Costs $10,000

LIHI Certification $5,000 Estimate--required for Tier I credits

Project Contingency $48,500

Total $533,500

Assumptions

Project Size 50kW

Contingency % 10%

Appendix C

Sample Hydropower Project B: Enhanced Investment and Production IncentivesOperating Proforma & Cash Flow Summary

Operating Proforma

Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 20 Cumulative

Revenues

Value of Electricity Saved $29,992 $30,202 $30,414 $30,627 $30,841 $31,057 $31,274 $31,493 $34,243 $641,466

Energy Production Credit $5,256 $5,256 $5,256 $5,256 $5,256 $5,256 $5,256 $5,256 $5,256 $105,120

Total $35,248 $35,458 $35,670 $35,883 $36,097 $36,313 $36,530 $36,749 $39,499 $746,586

Expenses

Operating & Maintenance Costs $2,999 $3,020 $3,041 $3,063 $3,084 $3,106 $3,127 $3,149 $3,424 $64,147

Annual LIHI Fee $1,000 $1,000 $1,000 $1,000 $1,000 $1,000 $1,000 $1,000 $1,000 $20,000

LIHI Recertification Fee $0 $0 $0 $0 $0 $3,750 $0 $0 $0 $13,250

Depreciation $17,783 $17,783 $17,783 $17,783 $17,783 $17,783 $17,783 $17,783 $17,783 $355,667

Total $21,783 $21,804 $21,825 $21,846 $21,867 $25,639 $21,911 $21,933 $22,208 $453,063

Net Revenues $13,466 $13,655 $13,845 $14,037 $14,230 $10,674 $14,620 $14,817 $17,291 $293,523

Cash Flow

Year 0 Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 20 Cumulative

Initial Capital Investment ($411,100) ($411,100)

Net Revenue 0 $13,466 $13,655 $13,845 $14,037 $14,230 $10,674 $14,620 $14,817 $17,291 $293,523

Depreciation 0 $17,783 $17,783 $17,783 $17,783 $17,783 $17,783 $17,783 $17,783 $17,783 $355,667

Total ($411,100) $31,249 $31,438 $31,628 $31,820 $32,013 $28,457 $32,403 $32,600 $35,075 $238,090

Cumulative ($411,100) ($379,851) ($348,413) ($316,784) ($284,964) ($252,951) ($224,494) ($192,091) ($159,491) $238,090

Total Payback Period (in Years) 12.9

Assumptions Notes

Turbine Capacity (in kW) 50

Operating Percentage 80% To account for unused capacity and down time

MWh Generated 350.4

Initial Electricity Price Savings per kWh $0.085

Annual Electricity Cost Escalation 0.7% Source: U.S. EIA

Operating & Maintenance Costs 10% As a percentage of electricity cost savings

Depreciation Schedule (Years) 30 Assume straight line method net of Investment Tax Credit

Energy Production Credit $0.015

Appendix C

Documents

Low-Impact Hydropower in Pennsylvania - Autos2050resource for small and micro hydropower (“microhydro”) projects. This potential is currently unrealized, with less than 1% of the