Modelling A Distributed Energy Resource (DER) …...3 I. Proposal Installing a 5-MW gas turbine and a 1-MW solar PV at New Jersey’s CSG Hospitali would reduce carbon emissions by

Modelling A Distributed Energy Resource (DER)

System To Achieve Resilience & Sustainability

CSG Hospital

New Jersey

C.S.G. Strategy Advisors, Inc.

Cathy Chen

Salman Tariq

Gabriel Guggisberg

March 8, 2017

2

Contents

I. Proposal ___________________________________________________________________________________________ 3

II. Current Situation ________________________________________________________________________________ 4

III. Objectives__________________________________________________________________________________________ 5

IV. Options _____________________________________________________________________________________________ 5

V. Quantitative Analysis ___________________________________________________________________________ 7

i. Business-as-Usual (BAU) Case __________________________________________________________________ 7

ii. Key Performance Indicators ____________________________________________________________________ 7

VI. Recommendation _______________________________________________________________________________ 10

VII. Risks and Mitigating Factors _________________________________________________________________ 13

VIII. Innovating for the Future _____________________________________________________________________ 14

IX. Appendices ________________________________________________________________________________________ 15

X. References _________________________________________________________________________________________ 31

3

I. Proposal

Installing a 5-MW gas turbine and a 1-MW solar PV at New Jersey’s CSG Hospitali would reduce

carbon emissions by 57%ii and increase resilience by over 90%. This will also lower the hospital’s

energy bill compared to purchasing power from the grid. After incorporating $1.65MM of state

and federal incentives, a first-year Power Purchase Agreement (PPA) price of 8¢/kWh would

enable the hospital to save up to $1.2MM annually.

At an after-tax IRR of 20% and above, the upfront capital investment of $5.5MM will be funded

by 44% of debt and 56% of equity. NRG would act as the tax equity investor in this non-recourse

project finance deal. Additional capital would be raised by using credit enhancements to keep

borrowing costs low with traditional banks. More innovative financing options include securitizing

projects with similar characteristics and leveraging big data analytics to find mid-market debt and

equity investors (Section VIII).

4

II. Current Situation

The increased frequency, unpredictability, and duration of extreme weather events caused by

climate change poses physical risks to the electric grid, in the form of blackouts and brownouts

that cut off the power supply to residential, commercial, and industrial customers. Hospitals are

especially vulnerable to power supply disruptions because many patients depend on life support

and lifesaving equipment, which in turn depends on a reliable electricity supply. As part of the

State of New Jersey’s efforts to bolster climate change adaptation and resilience after Hurricane

Sandy, hospitals have been identified as critical loads that must be able to withstand prolonged

exposure to blackouts. Therefore, many NJ hospitals are looking to update their energy supply and

to incorporate distributed energy resources (DER) as a way to mitigate their physical and financial

risks stemming from climate change and natural disasters.

In addition to serving as a risk-mitigation strategy, DER gives hospitals the opportunity to reduce

operating costs. Hospitals are extremely energy-intensive, consuming more than 2.5 times more

energy annually than the average commercial building.iii As a result, average hospital energy costs

exceed over $10 billion annually and account for over 2% of the operating budget.iv Moreover, the

price of electricity purchased from the utility is expected to rise above the current rate of 13¢/kWh.

In the next 25 years, total energy costs will climb by 40%.v

Moreover, as air pollution and extreme weather events are exacerbating public health issues, many

hospitals are looking to align their mission of quality healthcare with environmental stewardship

as a way to promote healthy communities. Since hospitals contributed to 10% of total U.S.

greenhouse gas emissions in 2013, there is a significant opportunity for hospitals to demonstrate

community leadership and to generate positive environmental impact.vi Healthcare practitioners

certainly understand the value of preventative care as a means to reduce the risk of disease. Climate

change mitigation as a means to reduce threats against community wellbeing and longevity is no

different.

However, hospital administrators do not view energy management as their core function. Since

key performance indicators for hospitals relate to patient care, capital budgeting generally goes

towards medical facilities and devices that have revenue-generating potential rather than energy

systems that may have cost-saving potential. What many healthcare administrators don’t realize is

that each dollar saved on energy equals a revenue increase of $20.vii Since hospitals have

traditionally financed energy investments on their balance sheets, this negatively impacts their

credit rating and ability to get debt financing.viii For this reason, many hospitals still operate on

backup diesel generators and continue to rely on the grid for electricity.

For these reasons, we regard the hospital customer segment as a strategic opportunity for NRG

and recommend targeting CSG Hospital, a 2,000-bed, 5-MW hospital in New Jersey. NRG can

5

step in to reduce CSG Hospital’s risk exposure to grid outages, its carbon footprint, and long-term

operating costs, while also eliminating the need for the hospital to incur high upfront capital costs

through a PPA.

III. Objectives

The primary objective was to create a robust generation profile that is both sustainable and cost-

effective for the customer. Since NRG’s core value proposition is delivering reliable, cost-

effective, and sustainable energy solutions to the customer, our team aimed to optimize profits for

NRG while maximizing value for NRG’s customer. What matters to the customer also matters to

NRG, which is why we operationalized and translated these shared objectives into the project’s

Key Performance Indicators (Table 1).

Table 1: Key Performance Indicators

Key Performance

Indicator (KPI) Unit of Analysis

CO2 Emissions

Reduction

Reduction in CO2 emissions (%) compared to the BAU scenario of

100% usage from grid.

System Resilience Self-sufficiency of the total load requirement without relying on the

grid (%).

Financial Returns For Investors: IRR (%)

For Hospital: Energy cost savings compared to BAU ($/year)

Building a robust business case for distributed generation that can be scaled up and replicated

easily would enable NRG to capture a greater share of the hospital customer segment going

forward and to raise capital from both traditional and innovative sources.

IV. Options

Technology choice was driven by an analysis of CSG Hospital’s peak and baseload requirements.

Because hospitals operate 24/7, their average load profile suggests that overall energy demand is

relatively flat with peaks occurring during the day, as opposed to residential peaks, which occur in

the evening.

We matched the hospital’s 8760 load curve with the generation profiles of four DER technologies

(Table 2) to determine the remaining demand that must be met by the grid. To match the shape of

this hospital’s load profile, we combined intermittent sources of generation with baseload sources

to arrive at two optimal combinations of DER technologies:

6

Option A: Solar PV + Gas Turbines

Option B: Solar PV + Fuel Cell + Battery Storage

Solar PV is the common denominator in both options because it is the most suitable intermittent

technology for this 2000-bed hospital. Given that the hospital has approximately 270,000 ft2 of

total rooftop space, this provides an attractive opportunity for solar PV installations. Moreover,

New Jersey has an average solar radiation level of 4.45 kWh/m2/day, approximately 19% greater

than the U.S. regions with the lowest solar potential.ix

Table 2: DER Technology Options

DER Technology Description

Solar PV ● Harnesses energy from the sun using semiconductors.

● Has become increasingly cost-effective.

● Complements the hospital’s daytime load peak.

Gas

Turbine

● Combustion engine that converts natural gas into electricity.

● Proven and robust technology, with big players such as Siemens, GE, and

Caterpillar.

Fuel Cell ● Converts chemical energy from natural gas into electricity with greater

efficiency than gas turbines.

● Quieter than turbine technologies.

Battery ● Stores energy produced at certain times for use at different times.

● Smooths out the generation profile of intermittent renewable energy sources.

We evaluated the two combinations of DER technologies in order to deliver the highest possible

impact on all three KPIs. To create a robust generation profile that is both sustainable and cost-

effective, we conducted both a qualitative (Table 3) and quantitative (Section V) analysis.

Table 3: Technological Capabilities and Constraints

Option Technologies Pros Cons

A Solar PV

Fuel Cell

Battery

Fewer emissions per kWh

Runs quietly

State incentives for fuel

cells available (if heat is

High capital cost for fuel

cells and batteries

Fuel cells and battery

storage are still in the

7

recovered)

State incentives for batteries

available

Higher thermal + electric

efficiency than gas turbines

early adoption stage

Higher interest rates due

to higher risk and less

access to financing

B Solar PV

Gas Turbine

Gas turbines have low

O&M costs

Reliable suppliers

State incentives available (if

heat is recovered)

Lower interest rates due to

lower technology risk and

greater access to financing

Lower efficiency

translating to higher

emissions

Noisy

Most of the cost

reduction in the gas

turbine technology has

taken place

V. Quantitative Analysis

i. Business-as-Usual (BAU) Case

Our baseline assumption is that the hospital currently draws all of its power from the grid.x We

compared the PPA price to average PJM tariffs for commercial & industrial customers and

compared emissions from the DER system options with average emissions of the PJM system.

Common assumptions for both options were kept the same, including interest rates, minimum

DSCR (for debt sizing), WACC (for NRG), and a loan tenor of 15 years. Since solar PV was

included in both options, the same metrics have been used for solar PV costs and operational

characteristics.

ii. Key Performance Indicators

The two DER system options were analyzed through the lens of emissions reduction, resilience,

and financial performance.

KPI #1: Emissions

The emissions savings were consistently higher for the fuel cell system. This is primarily due to

the fact that fuel cells have fewer emissions per kWh than gas turbines. Keeping system size (MW)

constant, fuel cells achieve 30% higher emissions savings than gas turbines.

8

Solar PV + Fuel Cell + Battery Solar PV + Gas Turbine

The system with 3.5MW solar and 1MW solar along with 3,000 kWh of battery storage saves

close to 80% emissions while the system with the 3.5-MW gas turbine and 1MW solar saves

close to 50%.

KPI #2: Resilience

When compared at the same rated capacity, fuel cells ensure 11% higher self-sufficiency of the

system than gas turbines due to the higher efficiencies, as shown below. Based on resilience alone,

the fuel cell system outperforms the gas turbine system.


The fuel cell system can meet 88% of the hospital’s power needs at a size of 3.5-MW. At the

same capacity, the gas turbine system can meet 75% of the hospital’s power needs.

KPI #3: Financial Considerations

The financial performance of both systems was analyzed based primarily on the leveraged after-

tax IRRs at different system sizes, PPA prices, and levels of state incentives. In addition, we

9

compared the Levelized Cost of Electricity (LCOE) of both systems.


The after-tax IRR of the fuel cell system at prices below 11¢/kWh returns an IRR of less than

10% with state incentives. The IRR exceeds 12% if first-year PPA price is at least 12¢/kWh,

which is close to the grid’s per-unit electricity price. This option gives the hospital little

opportunity to save on energy costs.

For the gas turbine system, 8¢/kWh gives returns of 20% with state incentives and over 12%

without state incentives. Running a sensitivity analysis with state incentives is key to

understanding the financial performance of the system in the event that State incentives are no

longer available.

Comparing both systems at a PPA price of 8¢/kWh and comparing at same system sizes

(3.5MW), the IRR of fuel cell system does not even pass the hurdle rate (assumed at 8% for

NRG). The gas turbine system, on the other hand, returns an IRR that is 10 times more than the

fuel cell system.

10

Comparing the LCOE at same system size of 3.5MW fuel/gas + 1MW solar, the LCOE is around

13¢/kWh for fuel cell system (same as grid prices) while LCOE for gas turbine system is less

than 9¢/kWh.

VI. Recommendation

Assuming a short-term implementation timeframe, we recommend that NRG develop the solar PV

+ gas turbine system at CSG Hospital to deliver on all three KPIs: resilience, emission savings,

and financial returns. With a 5-MW gas turbine and 1-MW solar PV system, the project will reduce

emissions by 57% and increase resilience by 90% while providing an attractive IRR of at least

20%.

Even though the solar PV + fuel cell + battery system outperforms the solar PV + gas turbine

system in terms of resilience and carbon emissions, it provides a significantly lower financial

return, below the hurdle rate of 8%.

The major drawback for the fuel cell system was the high capital cost. With our cost assumptions

and current NJ State incentives, the fuel cell system does not meet the financial KPI. However, in

Section VIII, we explore opportunities to grow this area in the future.

i. Project Sizing

We sized the project using a sensitivity analysis of the KPIs at different gas and solar PV sizes.

Emissions savings and resilience were highest at 1-MW solar PV and 5MW gas turbine, while the

leveraged, after-tax IRR remained above 20%. By increasing gas turbine size beyond 3.5 MW, the

leveraged, after-tax IRR started to decline. Beyond 5 MW, this decline would reduce IRR by 20%.

If financial maximization were our sole objective, a system size of 4 MW would be the ideal size.

Increasing the gas turbine from 4 to 5 MW will increase resilience by 10%, taking the overall

resilience of the system to over 90%, which is critical for hospitals.

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Average Load & Generation Profile Maximum Load & Generation Profile

ii. Capital Requirements

The total project cost is $5.5MM. The optimal debt size considering a 15-year loan tenor and a

1.3x DSCR is $2.44MM, which is 44% of the total cost. As follows, the equity requirement is

$3.05MM.

The Federal Solar ITC is worth $600,000 and State incentives on gas turbines portion are worth

$1.05MM under the Combined Heat & Power (CHP) incentives under New Jersey’s Clean Energy

Program.xi

iii. Financing Mechanisms

Given the small project debt size relative to the minimum thresholds of conventional investment

banks, NRG will need to tap into alternate sources of financing:

Securitized Green Bonds backed by the NJ Energy Resilience Bank (ERB): Given the

mandate of ERB to support critical industries like hospital to achieve resilience, ERB can

act as the guarantor for the loan to enhance the credit rating of the project. The long term

PPA will provide the project with steady cash flows. To establish a strong working

partnership with the ERB, NRG should engage the ERB as part of the company’s public

affairs strategy.

Property Assessed Clean Energy (PACE) Financing: While PACE has not been

implemented in New Jersey yet, this is a potential financing option for NRG to watch for

in the future, which could provide lower interest rates with longer debt tenors.

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RePower Capital’s “Online Financing of Clean Energy Projects”: This is a new concept

being pitched by RePower Capital in the 2017 Fire Awards to match capital needs of mid-

size projects with mid-market investors and lenders.

iv. Benefits for CSG Hospital

Assuming grid price of 13¢/kWh increasing at 1.5% annually and a PPA price of 8¢/kWh with an

annual escalation factor of 2%, the hospital saves over $1.2MM in power costs annually.

Table 4: Hospital Cost Savings

First-year

PPA Price

(¢/kWh)

Grid Price

Savings

(¢/kWh)

First-year Energy Cost Savings

8 5 $1,208,607

9 4 $966,885

1 3 $ 725,164

11 2 $483,443

12 1 $241,721

v. Marketing and Outreach Strategy

Engaging CSG Hospital effectively requires a deep understanding of the client’s needs and NRG’s

unique value proposition.

The $200MM that the NJ ERB allocated to hospitals for DER projects expired in September 2016.

NRG therefore fills an important market gap wherein hospitals that do not have the ability to bear

the full capital costs of DER projects without State incentives can opt to receive the same

resilience, sustainability, and financial benefits through a PPA with NRG.

Making hospitals sustainable and resilient creates value not only to the organization, but also to

the surrounding community. Given the dire consequences that hospitals must face during grid

outages and the fact that many lives depend on a reliable and constant source of electricity and

heat, we developed a marketing slogan for NRG tailored specifically to the hospital customer

segment.

“We give you the NRG to save lives.”

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VII. Risks and Mitigating Factors

Risk Description Mitigating Factors

Financing Raising capital for projects of this scale is

a challenge because investment banks are

unwilling to incur high transaction costs

for projects under $100MM.xii

Work with ERB to leverage

credit enhancements and

securitizing projects of

similar scale.

Regulatory State incentives for gas turbines are

applicable under CHP incentives in the

New Jersey Clean Energy Program.

However these funds are limited. The

total FY17 budget allocated was

$49.8MM out of which $6.9MM is

remaining. During FY16 budget, the total

cap for the C&I portfolio was $5MM but

fell to $3MM in FY17.

The system provides healthy

returns (12%+ IRR) even

without state incentives.

The state incentives under

CHP program are allocated a

budget every year, which may

continue in FY18.

Counterparty The financial health and creditworthiness

of CSG Hospital is critical to ensuring a

steady cash flow from the buyer of

energy to NRG. Investors will want to

see that the counterparty is financially

stable and has a sound track record of

meeting financial obligations.

Conduct due diligence on the

offtaker’s credit rating to

ensure low default risk.

Determine the potential

recovery rate in the event of

counterparty insolvency and

perform a ‘stress test’ on this

scenario.

SRECs can be an alternate

revenue source by

establishing a REC contract

with the utility if hospital

discontinues purchase of solar

system. The Solar Weighted

Average Price for EY2017

was $315/MWh.xiii

Fuel Since fuel prices are volatile, the risk is

higher total fuel costs than anticipated.

Hedge fuel price risk through

a futures contract.

Operational O&M costs may increase due to increases Procure insurance against

14

in the O&M escalation factor. Technical

risks may stem from measurement

inaccuracies in solar radiation levels.

property damage or business

interruption. The independent

engineer should be carefully

vetted and provide warranties

for minimum generation

capacities.

VIII. Innovating for the Future

Fuel Cells are an attractive technology for achieving resilience and reducing emissions. This

technology would outperform the gas turbine system if NRG could secure favorable prices from

preferred suppliers or if the State increases fuel cell incentives. However given the current cost

environment, fuel cells do not meet the project finance model’s financial KPI.

The current capital investment for fuel cells is $5,000/KW. Given a PPA price of 8¢/kWh and an

efficiency level of 70%, a 30% cost reduction would boost IRR to 8% and a 50% cost reduction

would ensure an IRR of 18%.

15

IX. Appendices

Appendix 1

Load Curve Data

A. Load Curve – Sample shots from financial model raw data (8760 values) – Gas + Solar

.

.

.

16

B. Load Curve – Sample shots from financial model raw data (8760 values)- Fuel Cells +

Solar + Battery

C. Load usage and generation– Maximum & Average values at each hour during the year

(Gas + Solar)

Hour Usage Solar Gas Solar + Gas Grid Hour Usage Solar Gas Solar + Gas Grid

1 4,235 - 3,000 3,000 1,235 1 2,435 0 2,397 2,397 209

2 3,955 - 3,000 3,000 955 2 2,239 0 2,229 2,229 200

3 3,558 - 3,000 3,000 558 3 2,115 0 2,112 2,112 175

4 3,149 - 3,000 3,000 149 4 1,989 0 1,988 1,988 149

5 3,217 - 3,000 3,000 215 5 2,168 0 2,167 2,167 137

6 3,547 20 3,000 3,020 514 6 2,578 4 2,521 2,525 208

7 3,492 244 3,000 3,244 492 7 2,791 52 2,676 2,728 140

8 4,259 259 3,000 3,259 1,025 8 3,003 98 2,554 2,652 543

9 4,561 672 3,000 3,672 1,314 9 3,173 267 2,549 2,816 582

10 5,000 800 3,000 3,800 1,740 10 3,476 400 2,707 3,107 614

11 5,000 851 3,000 3,851 1,670 11 3,539 459 2,713 3,172 604

12 5,000 868 3,000 3,868 1,725 12 3,640 511 2,743 3,254 667

13 5,000 901 3,000 3,901 1,776 13 3,723 522 2,791 3,313 734

14 5,000 886 3,000 3,886 1,800 14 3,775 508 2,809 3,317 770

15 5,000 880 3,000 3,880 1,882 15 3,807 500 2,856 3,356 781

16 5,000 848 3,000 3,848 1,892 16 3,542 451 2,784 3,235 766

17 5,000 793 3,000 3,793 1,866 17 3,252 372 2,716 3,088 681

18 5,000 653 3,000 3,653 1,910 18 3,270 254 2,836 3,090 603

19 4,896 239 3,000 3,239 1,764 19 3,032 96 2,767 2,863 487

20 4,439 219 3,000 3,219 1,434 20 2,938 51 2,784 2,835 332

21 4,529 18 3,000 3,018 1,529 21 3,014 4 2,830 2,834 333

22 4,256 - 3,000 3,000 1,256 22 2,861 0 2,717 2,717 296

23 4,099 - 3,000 3,000 1,099 23 2,688 0 2,590 2,590 258

24 3,043 - 3,000 3,000 43 24 1,943 0 1,943 1,943 43

Max Average

17

Appendix 2

Financial Model Assumptions

Assumptions for Solar

Installation & CAPEX

Project Capacity (kW DC) 1000

Total Capital Cost ($/W) 2

Total Installed Costs ($/KW) 2,000,000

Efficiency 18.5%

Yearly Panel Degradation 0.50%

PV Fixed O&M ($/kW) 25

Yearly Fixed O&M Escalation 1.5%

DC to AC Conversion Efficiency 95%

Incentives

Investment Tax Credit (ITC) 30%

Gas Turbines


Project Capacity (kW) 5,000

Total Capital Cost ($/KW) 700


Operational Parameters & Costs

Gas Price ($/ 1000 cu ft) 4

Gas price escalation 1%

Heat Rate (BTU/kWh) 12,500

Efficiency 60%

Variable O&M ($/kWh) 0.015

Fixed O&M ($/KW) 20

MMBTU to MCF 0.9756

Incentives/Unit for CHP $/KW KW Eligible for Incentive

<= 500kw 2000 500

>500 - 1MW 1000 500

>1MW-3MW 550 2000

>3MW 350 2000

Total State Incentives

3,300,000

$42m have already been utilized and remaining

budget is $6.9m as of Dec 31 2016 as per New

Jersey Clean Energy Program

Cap 1

3,000,000

Cap 2 (30% of project cost)

1,050,000

State Incentive Applicable 1,050,000

Incentive Disbursement:

Before Operation 80%

After 1st year data 20%

18

Fuel Cell Assumptions


Project Capacity (kW) 3500

Total Capital Cost ($/KW) 5,000



Gas Price ($/ 1000 cu ft) 4

Gas price escalation 1%

Heat Rate (BTU/kWh) 5,700

Efficiency 70%

Variable O&M ($/kWh) 0.03

MMBTU to MCF 0.9756

Incentives/Unit for Fuel Cells $/KW KW Eligible for Incentive

<= 500kw 2000 500

>500 - 1MW 1000 500

>1MW-3MW 550 2000

>3MW 350 500

Total State Incentives 2,775,000

Cap 1 3,000,000

Cap 2 (30% of project cost) 5,250,000

State Incentive Applicable 3,000,000

Incentive Disbursement:

Before Operation 80%

After 1st year data 20%

Batteries

Project Capacity (KW) 1000

Project Capacity (kWh) 3000

Total Installed Cost ($/KWh) 500

Total Costs 1,500,000


RT Efficiency 85%

Fixed O&M ($/KW) 40

Incentives/Unit for Battery $/KW

Incentive $/kWh 300

Cap 1 ($/Project) 300,000

Cap 2 (30% of project cost) 450,000

State Incentive Applicable

Total State Incentives 900,000

Cap 1 3,000,000

Cap 2 (30% of project cost) 450,000

State Incentive Applicable 450,000

Disbursement Before Operation 80%

Disbursement After 1st year data 20%

19

Common Assumptions

Prices

Initial PPA Price for whole system ($/kWh) 0.08

PPA Annual Escalation 2%

Increase in Grid Power costs 2%

Debt

Tenor (years) 15

Interest Rate 8.00%

Min DSCR 1.3x

Debt Type Mortgage

WACC 8%

Max Debt 70%

Emissions

PJM Emissions (KG/kWh) 0.460

Gas Turbine KG CO2 KG/ kWh 0.188

Fuel Cell KG CO2 KG/kWh 0.053

Taxes

Federal Tax Rate 35%

Source: PJM

20

Appendix 3

Sensitivity Analysis – Solar + Gas Turbines

3000 3500 4000 4500 5000

500KW Solar PV 0.084 0.084 0.084 0.084 0.085

800KW Solar PV 0.086 0.085 0.085 0.085 0.086

1000KW Solar PV 0.087 0.086 0.086 0.086 0.087

Gas Turbine Size (KW)

LCOE Sensitivity

3000 3500 4000 4500 5000

500KW Solar PV 38.6% 43.9% 48.6% 52.4% 55.4%

800KW Solar PV 40.3% 45.6% 50.2% 53.9% 56.6%

1000KW Solar PV 41.5% 46.7% 51.3% 54.8% 57.4%

Emission Saving Sensitivity

Gas Turbine Size (KW)

0.07 0.08 0.09 0.1 0.11

State Incentive Applicable 6.5% 20.7% 48.8% 62.5% 75.2%

Without State Incentive 3.6% 12.6% 35.2% 47.8% 59.2%

First Year PPA Price ($/kWh)

After Tax Levered IRR

3000 3500 4000 4500 5000

500KW Solar PV 36.8% 27.9% 19.9% 13.4% 8.5%

800KW Solar PV 35.1% 26.2% 18.4% 12.1% 7.5%

1000KW Solar PV 33.9% 25.1% 17.4% 11.4% 7.0%

Gas Turbine Size

Grid Dependency Sensitivity

3000 3500 4000 4500 5000

500KW Solar PV 30.2% 30.7% 30.1% 28.3% 25.7%

800KW Solar PV 24.8% 25.5% 25.4% 24.2% 22.3%

1000KW Solar PV 22.5% 23.3% 23.2% 22.2% 20.7%

Gas Turbine Size

After Tax IRR - Levered (Tax Efficient Basis) Sensitivity

500 800 1000 1200 1500

50% Fuel Cell Efficiency 25.0% 14.8% 11.5% 9.2% 6.8%



Cost Per KW Gas Turbine


21

5% 6% 7% 8% 9%

1.1x 36.4% 35.3% 29.5% 25.4% 22.5%

1.2x 34.9% 29.2% 25.3% 22.5% 20.4%

1.3x 29.4% 25.6% 22.8% 20.7% 19.1%

1.4x 26.0% 23.2% 21.1% 19.4% 18.1%

1.5x 23.7% 21.5% 19.8% 18.5% 17.4%


Interest Rates

Minimum

DSCR

22

Appendix 4

Sensitivity Analysis – Fuel Cells + Solar PV + Battery

2000 2500 3000 3500 4000

500KW Solar PV 0.115 0.121 0.125 0.129 0.134

800KW Solar PV 0.116 0.121 0.125 0.129 0.135

1000KW Solar PV 0.116 0.122 0.125 0.130 0.135

Fuel Cell Size (KW)

LCOE Sensitivity

2000 2500 3000 3500 4000

500KW Solar PV 45% 55% 65% 74% 81%

800KW Solar PV 47% 57% 67% 76% 82%

1000KW Solar PV 48% 58% 68% 77% 83%

Fuel Cell Size (KW)

Emission Saving Sensitivity

0.07 0.08 0.09 0.11 0.13

State Incentive Applicable -0.6% 2.1% 5.0% 12.5% 27.9%

Without State Incentive -2.5% -0.2% 2.1% 7.4% 15.4%

First Year PPA Price


2000 2500 3000 3500 4000

500KW Solar PV 49.7% 38.1% 26.8% 16.7% 9.2%

800KW Solar PV 47.9% 36.4% 25.0% 15.3% 8.3%

1000KW Solar PV 46.7% 35.2% 23.9% 14.4% 7.7%

Fuel Cell Size

Grid Dependency Sensitivity

2000 2500 3000 3500 4000

500KW Solar PV 5% 4% 3% 2% 1%

800KW Solar PV 6% 4% 3% 2% 1%

1000KW Solar PV 6% 4% 3% 2% 1%


Fuel Cell Size

23

2500 3000 3500 4000 5000

70% Turbine Efficiency 18.4% 12.8% 8.4% 5.6% 2.1%



Cost Per KW Fuel Cell


24

Appendix 5

Debt Sizing (Solar +Gas)

Debt Schedule 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

CFADS (4,660,000) 370,587 1,207,226 424,499 452,421 481,006 510,267 540,219 570,877 602,257 634,373 667,242 700,879 735,301 770,525 806,568 843,447 881,180 919,786 959,283 999,689

Min CADS 370,587

Debt Service 285,067

Debt Facility 2,440,025

Debt % 44.4%

Beginning of the Year 2,440,025 2,350,160 2,253,106 2,148,287 2,035,083 1,912,823 1,780,781 1,638,177 1,484,164 1,317,830 1,138,190 944,178 734,645 508,350 263,951 0 0 0 0 0

Amortization 89,865 97,054 104,819 113,204 122,260 132,041 142,604 154,013 166,334 179,641 194,012 209,533 226,295 244,399 263,951 0 0 0 0 0

End of Year 2,350,160 2,253,106 2,148,287 2,035,083 1,912,823 1,780,781 1,638,177 1,484,164 1,317,830 1,138,190 944,178 734,645 508,350 263,951 0 0 0 0 0 0

Year Number

Interest 195,202 188,013 180,248 171,863 162,807 153,026 142,463 131,054 118,733 105,426 91,055 75,534 58,772 40,668 21,116 0 0 0 0 0

Principal 89,865 97,054 104,819 113,204 122,260 132,041 142,604 154,013 166,334 179,641 194,012 209,533 226,295 244,399 263,951 0 0 0 0 0

Debt Service 285,067 285,067 285,067 285,067 285,067 285,067 285,067 285,067 285,067 285,067 285,067 285,067 285,067 285,067 285,067 0 0 0 0 0

DSCR 1.300 4.235 1.489 1.587 1.687 1.790 1.895 2.003 2.113 2.225 2.341 2.459 2.579 2.703 2.829 0 0 0 0 0

Min DSCR 1.3

25

Appendix 6

LCOE Solar + Gas

LCOE Model Total PV 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Discount Factor 1.08 1.17 1.26 1.36 1.47 1.59 1.71 1.85 2.00 2.16 2.33 2.52 2.72 2.94 3.17 3.43 3.70 4.00 4.32 4.66

Fuel Costs 1,099,946 1,110,946 1,122,055 1,133,276 1,144,609 1,156,055 1,167,615 1,179,291 1,191,084 1,202,995 1,215,025 1,227,175 1,239,447 1,251,842 1,264,360 1,277,004 1,289,774 1,302,671 1,315,698 1,328,855

Maintenance costs 463,237 463,612 463,993 464,379 464,771 465,169 465,573 465,983 466,399 466,822 467,250 467,686 468,127 468,576 469,031 469,493 469,962 470,437 470,920 471,411

Interest Cost 195,202 188,013 180,248 171,863 162,807 153,026 142,463 131,054 118,733 105,426 91,055 75,534 58,772 40,668 21,116 0 0 0 0 0

Total Expenditure 1,758,385 1,762,571 1,766,296 1,769,518 1,772,186 1,774,250 1,775,651 1,776,329 1,776,217 1,775,243 1,773,331 1,770,395 1,766,346 1,761,085 1,754,507 1,746,496 1,759,735 1,773,109 1,786,619 1,800,266

Present Value of Expenditure 17,367,934 1,628,135 1,511,120 1,402,143 1,300,648 1,206,120 1,118,078 1,036,075 959,695 888,551 822,281 760,551 703,048 649,482 599,581 553,094 509,786 475,602 443,719 413,981 386,244

Capital Cost 4,660,000

Total Costs 22,027,934

Total KWh 24,172,131 24,164,016 24,155,941 24,147,907 24,139,913 24,131,959 24,124,045 24,116,171 24,108,335 24,100,539 24,092,782 24,085,064 24,077,384 24,069,743 24,062,140 24,054,575 24,047,048 24,039,558 24,032,106 24,024,691

Present Value of kWh 236,778,971 22,381,603 20,716,749 19,175,765 17,749,433 16,429,219 15,207,228 14,076,149 13,029,217 12,060,170 11,163,213 10,332,981 9,564,510 8,853,204 8,194,810 7,585,390 7,021,301 6,499,170 6,015,876 5,568,529 5,154,454

LCOE (unsubsidized) 0.093

Total Costs with Incentives 20,493,489.61

PV of kWh 236,778,970.75

LCOE (subsidized) 0.087

26

Appendix 7

Income Statements – Solar + Gas

1.0 - Taxable Income - Levered 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Revenue 1,933,770 1,971,784 2,010,547 2,050,076 2,090,385 2,131,491 2,173,407 2,216,152 2,259,741 2,304,190 2,349,517 2,395,740 2,442,876 2,490,942 2,539,959 2,589,943 2,640,915 2,692,895 2,745,901 2,799,955

Expenses (1,563,183) (1,574,558) (1,586,048) (1,597,655) (1,609,380) (1,621,224) (1,633,188) (1,645,275) (1,657,484) (1,669,817) (1,682,276) (1,694,861) (1,707,575) (1,720,417) (1,733,391) (1,746,496) (1,759,735) (1,773,109) (1,786,619) (1,800,266)

EBITDA 370,587 397,226 424,499 452,421 481,006 510,267 540,219 570,877 602,257 634,373 667,242 700,879 735,301 770,525 806,568 843,447 881,180 919,786 959,283 999,689

Less: Interest Expense (195,202) (188,013) (180,248) (171,863) (162,807) (153,026) (142,463) (131,054) (118,733) (105,426) (91,055) (75,534) (58,772) (40,668) (21,116) 0 0 0 0 0

Less: Tax Depreciation (1,100,000) (1,760,000) (1,056,000) (633,600) (633,600) (316,800) 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Taxable Income (Loss) (924,615) (1,550,787) (811,749) (353,042) (315,401) 40,441 397,757 439,823 483,524 528,947 576,187 625,345 676,529 729,857 785,452 843,447 881,180 919,786 959,283 999,689

Tax Benefits (payments) 323,615 542,775 284,112 123,565 110,390 (14,154) (139,215) (153,938) (169,233) (185,131) (201,665) (218,871) (236,785) (255,450) (274,908) (295,206) (308,413) (321,925) (335,749) (349,891)

Investment Tax Credits 0 600,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

State Incentives 840,000 0 210,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Total Tax Benefits (Payments) 840,000 323,615 1,352,775 284,112 123,565 110,390 (14,154) (139,215) (153,938) (169,233) (185,131) (201,665) (218,871) (236,785) (255,450) (274,908) (295,206) (308,413) (321,925) (335,749) (349,891)

1.1 - Cash Flow to Equity - Levered 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

EBITDA 370,587 397,226 424,499 452,421 481,006 510,267 540,219 570,877 602,257 634,373 667,242 700,879 735,301 770,525 806,568 843,447 881,180 919,786 959,283 999,689

Less: Debt Service (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) 0 0 0 0 0

Cash Distributions to Equity 85,520 112,159 139,432 167,354 195,939 225,200 255,152 285,810 317,190 349,306 382,175 415,812 450,234 485,458 521,501 843,447 881,180 919,786 959,283 999,689

Add: Tax Benefits (Payments) 323,615 542,775 284,112 123,565 110,390 (14,154) (139,215) (153,938) (169,233) (185,131) (201,665) (218,871) (236,785) (255,450) (274,908) (295,206) (308,413) (321,925) (335,749) (349,891)

Add: ITC 0 600,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Add: State Incentives on CHP 840,000 0 210,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

After- Tax Cash Flow to Equity (2,219,975) 409,135 1,464,934 423,545 290,919 306,329 211,045 115,937 131,872 147,957 164,175 180,509 196,941 213,449 230,008 246,593 548,240 572,767 597,861 623,534 649,798

After Tax IRR - Levered (Tax Efficient Basis) 21%

2.0 - Tax Income - Unlevered 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

EBITDA 370,587 397,226 424,499 452,421 481,006 510,267 540,219 570,877 602,257 634,373 667,242 700,879 735,301 770,525 806,568 843,447 881,180 919,786 959,283 999,689

Less: Tax Depreciation (1,100,000) (1,760,000) (1,056,000) (633,600) (633,600) (316,800) 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Taxable Income/(Loss) (729,413) (1,362,774) (631,501) (181,179) (152,594) 193,467 540,219 570,877 602,257 634,373 667,242 700,879 735,301 770,525 806,568 843,447 881,180 919,786 959,283 999,689

Tax Benefits (Payments) 255,295 476,971 221,025 63,413 53,408 (67,713) (189,077) (199,807) (210,790) (222,031) (233,535) (245,308) (257,355) (269,684) (282,299) (295,206) (308,413) (321,925) (335,749) (349,891)

ITC 0 600,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

State Incentives 840,000 0 210,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Total Tax Benefits (payments) 840,000 (474,118) (75,803) (410,475) (117,766) (99,186) 125,753 351,142 371,070 391,467 412,343 433,707 455,571 477,946 500,841 524,269 548,240 572,767 597,861 623,534 649,798

2.1 - Cash Flow to Equity - UnLevered

EBITDA 370,587 397,226 424,499 452,421 481,006 510,267 540,219 570,877 602,257 634,373 667,242 700,879 735,301 770,525 806,568 843,447 881,180 919,786 959,283 999,689

Cash Distributions to Equity 370,587 397,226 424,499 452,421 481,006 510,267 540,219 570,877 602,257 634,373 667,242 700,879 735,301 770,525 806,568 843,447 881,180 919,786 959,283 999,689

Add: Tax Benefits (Payments) 255,295 476,971 221,025 63,413 53,408 (67,713) (189,077) (199,807) (210,790) (222,031) (233,535) (245,308) (257,355) (269,684) (282,299) (295,206) (308,413) (321,925) (335,749) (349,891)

Add: ITC 0 600,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Add: State Incentives 840,000 0 210,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

After- Tax Cash Flow to Equity (4,660,000) 625,882 1,684,197 645,525 515,834 534,414 442,553 351,142 371,070 391,467 412,343 433,707 455,571 477,946 500,841 524,269 548,240 572,767 597,861 623,534 649,798

After Tax IRR Unlevered 12%

3.1. - Pre-Tax Cash Flow to Equity - Levered

Equity Contribution (3,059,975)

Incentives 840,000 0 810,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

EBITDA 370,587 397,226 424,499 452,421 481,006 510,267 540,219 570,877 602,257 634,373 667,242 700,879 735,301 770,525 806,568 843,447 881,180 919,786 959,283 999,689

Debt Service (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) (285,067) 0 0 0 0 0

Cash Flow to Equity (2,219,975) 85,520 922,159 139,432 167,354 195,939 225,200 255,152 285,810 317,190 349,306 382,175 415,812 450,234 485,458 521,501 843,447 881,180 919,786 959,283 999,689

IRR 15%

3.2 - Pre-Tax Cash Flow to Equity - UnLevered

Equity Contribution (5,500,000)

Incentives (Federal + State) 840,000 0 810,000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

EBITDA 0 370,587 397,226 424,499 452,421 481,006 510,267 540,219 570,877 602,257 634,373 667,242 700,879 735,301 770,525 806,568 843,447 881,180 919,786 959,283 999,689

Cash Flow to Equity (4,660,000) 370,587 1,207,226 424,499 452,421 481,006 510,267 540,219 570,877 602,257 634,373 667,242 700,879 735,301 770,525 806,568 843,447 881,180 919,786 959,283 999,689

IRR 12%

27

Appendix 8

Technical Specifications

28

Appendix 9 Power Purchase Agreement (PPA) Summary Term Sheet

GENERAL TERMS

Seller NRG Energy, Inc.

Buyer CSG Hospital Corp.

Scope of

Agreement

& Facility

Seller will sell to the Buyer up to 6 MW of electrical output (“Electrical

Output”). The solar and gas turbine CHP system has 6 MW of installed capacity

(“Contract Capacity”) and is comprised of solar PV panels, a gas turbine, and

related equipment (“System”).

Term &

Conditions

for COD

The term begins on the Commercial Operation Date (COD) over a period of 20

years. COD occurs when all contemplated and required facilities and rights allow

for 8,760 hours per year of regular operations, notwithstanding hours for

scheduled repairs with a predetermined duration (“Planned Outage”), not

including energy used to operate the Plant itself (“Commercial Operation”).

Contract

Price

$80.00 per MWh with an annual escalation factor of 2%

Other

Relevant

Economic

Terms and

Conditions

Seller’s Failed Delivery Payment: Without Buyer’s written consent, if Seller

sells any energy or attributes to a third party other than as permitted during Force

Majeure events that are beyond the Seller’s control, during Buyer’s Event of

Default (see Warranties, Default, and Termination), or when Buyer fails to

receive the contracted output, then Seller shall pay liquidated damages equal to

the difference between the Buyer’s replacement and contract price multiplied by

the quantity of undelivered output.

Buyer’s Failed Acceptance Payment: If Buyer fails to receive the contracted

output other than as permitted during Force Majeure or dangerous situations

(“Emergency Conditions”), Buyer shall pay $80.00 per MWh of undelivered

contracted output.

Delay

damages

Seller shall pay $500 for each day the COD is delayed, up to a limit of $7,000,

by the 20th day of the subsequent month of delay damage accrual.

Guaranteed

Output,

Dispatch,

Excess

Energy

There is no minimum guaranteed output except the Electrical Output generated

each hour, up to the Contract Capacity. Seller is not responsible for energy that

is undispatchable due to solar unavailability, Force Majeure, Planned Outages,

unplanned system failures, and Emergency Conditions that are not within the

control of Seller.

OPERATIONS AND MAINTENANCE

Seller’s

Obligations

Seller will operate and maintain the Plant in accordance with industry best

practices. Seller will provide to Buyer the Electrical Output scheduling and

reporting information, perform required capacity tests and calculations at

Buyer's expense, and provide any relevant data with respect to ordinary

operations of the Plant.

Administrative

Requirements

and Reporting

1) Seller shall insure the Plant at an amount comparable to industry best

practices. Upon 15 days of the Buyer’s request, Seller shall disclose the

name of the insurer, policy number, expiration date, coverage, and

29

1)

Insurance

2)

Capacity

Testing

3)

Metering

4)

Operating

Performance

deductibles or self-insured retentions. Seller can self-insure within

statutory bounds but must provide Buyer with proof of self-insurance.

2) Seller shall notify Buyer of and conduct capacity tests. Both parties

should approve and coordinate testing. Buyer is responsible for ensuring

reliability prior to testing without unnecessarily withholding testing

approval.

3) Seller shall ensure Buyer receives hourly metering data of actual

electricity at the Delivery Point. Seller will notify Buyer and pay for

meter inspections at least once every year. At Buyer’s expense and

request with at least 20 days notice, additional meter inspections can be

conducted if the meters are within two percentage points of accuracy.

4) Buyer and Seller shall mutually agree and develop written operating

procedures (“Operating Procedures”) including daily communication

procedures, key personnel lists, unplanned and planned service

disruption, and Electrical Output scheduling and reporting information.

Buyer and Seller will keep complete and accurate plant administrative

records for a minimum of 2 years and provide access to non-privileged

records subject to confidentiality requirements. On or before the 20th day

of each month, the Seller will provide a monthly progress report stating

the percentage completion and summary of construction activity

completed in the preceding month and contemplated for the upcoming

month.

Approvals &

Compliance

Seller will procure government approvals required to construct, operate, and

maintain the Plant and execute obligations under the PPA. Both Seller and

Buyer will comply with laws, government approvals, and transmission

requirements to perform its obligations under the PPA.

Billing &

Payment

Seller shall bill Buyer by the 15th day of each month for Electrical Output at

the Contract Price in line with Seller’s reading of meters and for delivery

charges to Buyer loads beyond the Delivery Point incurred in the previous

month. Buyer is responsible for payment, due on the first business day 10

days after the Buyer’s receipt of the invoice. Buyer can dispute the amount

due and pay the appropriate amount with supporting documentation. Any

outstanding balance resolved by Buyer and Seller will be due within 5

business days of resolution. Late payment interest charges are calculated

using the Wall Street Journal’s prime rate plus a 3% margin for the actual

days elapsed from the day after the due date to the payment date, inclusive.

Overpayment due to the error of the party receiving payment will be

reimbursed at the aforementioned prime rate plus a 3% margin for the actual

days elapsed from the day after the overpayment to the reimbursement date,

inclusive. Offsets of amounts receivable and payable are permitted with

written notice to the other party. Each party has the right, with written request

and at its own expense, to audit the other party’s financial records.

WARRANTIES, DEFAULT AND TERMINATION

Representation

& Warranties

The Agreement is legally binding and enforceable against Seller and Buyer.

Both Seller and Buyer have financial ability to deliver and pay for the

30

Electrical Output, respectively, and there is no pending legal or regulatory

action against either party. Seller is a limited liability company with the

power and authority to conduct its business and perform its obligations

under the Agreement, which does and will not require consent by Seller’s

members, violate any legal provisions, create any mortgage on Seller’s

assets, or breach any organizational documents, loans, or other agreements

tied to the Seller’s assets. Buyer is a corporation with the power and

authority to conduct its business and perform its obligations under the

Agreement, which does not and will not require consent by Buyer’s board of

directors or shareholders, violate any legal provisions, create any mortgage

on Buyer’s assets, or breach any incorporation articles, loans, or other

agreements tied to the Seller’s assets.

Termination

1) Early

Termination

Rights

Buyer can terminate the Agreement, with written notice to financiers

(“Financing Parties”) and Seller, if the COD is not reached within 6 months,

and Seller shall not pay a termination fee. Seller may terminate the PPA if

government permits and approvals are not obtained. The scheduled COD

will be extended if a Force Majeure event happens before Commercial

Operation, but if this disruption continues for over a year without efforts

consistent with industry best practices (“Commercially Reasonable Efforts”)

to overcome it, then the Agreement may be terminated upon written notice

to the affected Party. Liabilities incurred before the termination date must be

paid.

Events of

Default

1) Seller

2) Buyer

Seller’s Event of Default occurs when Seller does not pay its dues within 10

days of Buyer’s written notice; fails to comply with Agreement or cure such

failure within 50 days of Buyer’s written notice; is unable to pay debts; files

for bankruptcy; fails to defend against bankruptcy petitions; becomes

insolvent; and abandons Plant construction or operations for more than 100

consecutive days, notwithstanding Force Majeure events. Buyer’s Event of

Default occurs when Buyer does not pay dues within 10 days of Seller’s

written notice; fails to comply with Agreement and cure failure within 50

days of Seller’s written notice; is unable to pay debts; files for bankruptcy;

fails to defend against petitions under bankruptcy law; becomes insolvent;

fails to remedy any false representation within 50 days of Seller’s written

notice; and fails to accept delivery of Electrical Output for reasons other than

Force Majeure and Emergency Conditions.

Remedies The non-defaulting party may terminate the agreement upon notifying the

defaulting party of the termination date, offset the outstanding amounts

payable and receivable, and pursue other legal remedies. Financing Parties

may cure Seller’s Event of Default within cure periods specified in the

Events of Default section.

Force Majeure Events that are beyond the control, fault, or negligence of the affected Party,

including but not limited to, acts of God, natural disasters, terrorism, war,

riots, strikes, and expropriation but not including payment obligations under

the Agreement, changes in market conditions, or economic hardship

Governing

Law

The laws of the State of New Jersey

31

X. References

i Fictional hospital created for the purposes of this case competition.

ii Compared to our assumed baseline (see Appendix).

iiiDeep Dive on Microgrid Financing. Technical paper. Accessed March 8, 2017.

https://w3.usa.siemens.com/smartgrid/us/en/microgrid/Documents/Siemens_Microgrid_Financin

g_eBook.pdf.

ivIbid.

v Annual Energy Outlook 2017 with projections." Accessed February 27, 2017.

https://www.eia.gov/outlooks/aeo/pdf/0383(2014).pdf.

vi Cohen, Ronnie. "Hidden harm: US healthcare emits more greenhouse gas than entire UK."

Reuters. June 22, 2016. Accessed March 8, 2017. http://www.reuters.com/article/us-health-

hospitals-pollution-idUSKCN0Z82FR

vii "Local Topics - Energy Efficiency in Non-Governmental Buildings." Www.epa.gov. Accessed

March 8, 2017. https://www.epa.gov/statelocalclimate/local-topics-energy-efficiency-non-

governmental-buildings.

viiiDeep Dive on Microgrid Financing. Technical paper. Accessed March 8, 2017.

https://w3.usa.siemens.com/smartgrid/us/en/microgrid/Documents/Siemens_Microgrid_Financin

g_eBook.pdf.

ix Solar Power in New Jersey. March 8, 2017. Accessed March 1, 2017.

https://solarenergylocal.com/states/new-jersey/.

x All assumptions are available in the Appendix.

xi "Combined Heat & Power." New Jersey Clean Energy Program. December 31, 2016. Accessed

March 8, 2017. http://www.njcleanenergy.com/chp.

xii Van Dyck, Wayne. "Online Financing Of Clean Energy Projects." Finance for Resiliance.

January 1, 2017. Accessed March 8, 2017. http://www.financeforresilience.com/priority/online-

financing-clean-energy-projects/.

xiii "SREC Pricing New Jersey." New jersey´s Clean Energy Program. March 1, 2017. Accessed

March 8, 2017. http://www.njcleanenergy.com/srecpricing.

http://www.reuters.com/article/us-health-hospitals-pollution-idUSKCN0Z82FR

http://www.reuters.com/article/us-health-hospitals-pollution-idUSKCN0Z82FR

http://www.njcleanenergy.com/chp

http://www.financeforresilience.com/priority/online-financing-clean-energy-projects/

http://www.financeforresilience.com/priority/online-financing-clean-energy-projects/