Economic Outcomes of an Increased Offshore Wind Energy Target

Rhode Island “Energy 2035”: Economic Outcomes of an Increased Offshore Wind Energy Target

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Economic Outcomes of an Increased Offshore Wind Energy Target

Anthony DeOrsey

A Thesis in the Field of Sustainability for the Degree of Master of Liberal Arts in Extension Studies

Harvard University

November 2017

Abstract

This thesis explores changes to current Rhode Island energy policy that may increase the profitability of Deepwater Wind’s Block Island Wind Farm (BIWF) offshore wind farm. The BIWF project has gained only modest investment, despite winning leasing rights to a high-velocity wind area capable of supporting a much larger offshore wind operation. In 2015, the Rhode Island Division of Planning (RIDOP) promulgated a proposal entitled “Energy 2035” that put forth a suggested Renewable Energy Standard

(RES) for offshore wind of 180 megawatts (MW).

The research conducted throughout this thesis aimed to understand the impact of

Rhode Island’s RES on the profitability of the BIWF. I assumed that through improved markets for energy generated from offshore wind markets, the BIWF project will better attract investment for a larger project as a larger project will make more efficient use of fixed costs. Furthermore, this research endeavored to understand the potential for an increased role of offshore wind in the RES targets to provide an economical alternative to

Rhode Island’s energy consumers while also improving benefits to the local economy.

Specifically, the profitability of the BIWF was analyzed within the context of three hypothetical scenarios of an increased RES (10%, 20%, 30%, compared to current goals). Each scenario examined a proposed expansion of the BIWF project equal to that of the target increase. The goal of this research was to discover whether within at least one of these three scenarios consumer prices can be reduced by up to 10% and net present value (NPV) can improve by as much as 20%. Additionally, the results of this research

were intended to indicate whether energy produced by the BIWF could at least break even under the average price of electricity in Rhode Island, while also tripling the amount of long-term annual jobs generated by the BIWF, currently predicted to be 17.

Within each scenario, the change in breakeven prices, internal rate of return, net present value, and benefits to the local economy were predicted. Data on pricing, investment, and energy generation was gathered from Deepwater Wind filings prior to construction, the U.S. Energy Information Administration, and from outputs generated by the National Renewable Energy Laboratory’s (NREL) Jobs and Economic Development

Index (JEDI) model. The cost of energy generation from the BIWF was calculated using levelized cost of energy (LCOE) calculations and compared with natural gas using levelized avoided cost of energy (LACE). The case for investors under each of the augmented scenarios included calculations of net present value (NPV), internal rate of return (IRR), and cash flow analyses. Net benefits to the local economy made use of the

JEDI model. Additionally, the amount of carbon dioxide equivalent (CO2e) displaced by offshore wind was quantified, as will the associated cost of mitigation.

Economic results produced by the JEDI model indicated that impacts in job creation and local economic output can be increased by as much as 30% when the BIWF is expanded to 234 MW (30% higher than the 180 MW target in Energy 2035).

Moreover, annual job creation and economic output increase by factors of 7.3 and 7.2 respectively under the 234 MW scenario versus the current 30 MW wind farm.

Breakeven prices of electricity predicted from a expanded BIWF were less than half of the PPA price currently in place for the BIWF, indicating potential for lower end prices for consumers. Financial models run on data extrapolated from the current Deepwater

Wind cash flows and the U.S. Energy Information Administration (EIA) indicate a significant risk of negative NPV and a partial risk of below-average IRR. The JEDI model results, however, predicted considerably higher IRR and NPV, which would indeed be attractive to potential investors. A key distinction between the JEDI model results and results from other models is that capital expenditures (CAPEX) were predicted to be much lower in the JEDI models, indicating a critical importance of

CAPEX reduction for improved offshore wind investment theses.

The significance of this research is understanding the precedent that the BIWF’s success or failure will establish for planned and future offshore wind projects in the U.S.; investors will likely look to this case as a template for cost-to-benefit assumptions.

Exploring the potential changes in project costs across various project sizes allows stakeholders to weigh the offshore wind status quo against policy intervention options.

Author’s Biographical Sketch

The author was born and raised in Cranston, Rhode Island. After completing a bachelor’s in political science from the University of Rhode Island, the author moved to

China, where he spent five years living and working. The author’s interest in the intersection of sustainability and industry first arose while working as the marketing manager for a natural daily-use products startup headquartered in Shanghai, Eco&More.

The author spent two and a half years as marketing manager for Eco&More, before leaving for a position at China market-entry firm, China Integrated, where he worked for three years. Currently, the author is based in Somerville, Massachusetts, where he works as deputy general manager of TechCode Accelerator, a global startup acceleration company with twenty-two locations worldwide and a focus on developing startups in the fields of artificial intelligence, medical technology, clean technology, and new materials.

Dedication

This thesis is dedicated to the engineers, scientists, researchers, investors, and policymakers that will lead the development of offshore wind in the United States in the coming decades. It is the author’s hope that U.S. policymakers will recognize the consensus of the scientific community with regard to climate change and that members of the private sector prioritize developing industries with potential for sustainable outcomes.

vii Acknowledgments

I would like to extend sincere thanks to Rich Goode for his support in developing this thesis; successful completion of the research and calculations included in this thesis was only possible because of Mr. Goode’s guidance. I would also like to acknowledge the work of Dr. Mark Leighton, whose “Critical Analysis of Ecosystems” course inspired me to pursue the sustainability master’s program. Further acknowledgements are due to faculty members Ramon Sanchez, Nicholas Ashford, Jack Spengler, and George Buckley for creating a curriculum that intelligently places sustainability at the nexus of industrial growth, national development, and public health. I am grateful for the leadership that

Harvard University displays, both locally and globally, in the pursuit of a sustainable future.

Equal in importance has been the support of my wife, He Zhuoyin. Her unwavering support, encouragement, and patience have been instrumental in both my educational pursuits and career. My wife’s perseverance in the face of adversity, both past and recent, is a testament to power of self-determination, I am inspired by you every day. I would also like to acknowledge my parents, Karen and Brian, for the example that they set for me throughout my life, it is because of them that I have gained the motivation to face challenges and the resolve to overcome them. I am grateful to my sisters, Ashley and Amanda, for their encouragement throughout the course of my master’s education, while I do concede that they are both smarter than me, I maintain that I am more interesting.

viii Table of Contents

Author’s Biographical Sketch ...... vi

Dedication ...... vii

Acknowledgments...... viii

List of Tables ...... xi

List of Figures ...... xiii

Definition of Terms...... xiv

I. Introduction ...... 1

Research Significance and Objectives ...... 3

Background ...... 5

Rhode Island’s Energy 2035 ...... 6

Rhode Island’s Energy Supply...... 7

Offshore Wind in the United States ...... 9

Offshore Wind Potential in the Block Island Sound ...... 11

Previous Attempts at Offshore Wind Projects in the Atlantic ...... 13

Offshore Wind Policy in Europe...... 14

Deepwater Wind ...... 16

Deepwater Wind Power Purchase Agreement ...... 17

Environmental Impacts of Deepwater Wind...... 18

Block Island Wind Farm Financial Analysis ...... 19

Proposed Economic Outcomes of Energy 2035 ...... 22

ix Research Questions, Hypothesis, and Specific Aims ...... 23

II. Methods ...... 24

III. Results ...... 30

IV. Discussion ...... 49

Conclusions ...... 49

Recommendations ...... 53

Research Limitations ...... 55

Appendix Project Cash Flow Analyses...... 57

References ...... 85

List of Tables

Table 1 Energy 2035 proposed target increase scenarios...... 2

Table 2 North and South Zone offshore wind capacity...... 13

Table 3 Government support per technology in Europe (includes GHG credits) ...... 16

Table 4 Block Island Wind Farm cash flow during construction...... 20

Table 5 Block Island Wind Farm project cost estimate ...... 21

Table 6 Block Island Wind Farm contribution to RI GDP...... 21

Table 7 Average MWh per year and CAPEX for five scenarios...... 30

Table 8 JEDI cost model – current Block Island Wind project...... 31

Table 9 JEDI benefit model – current Block Island Wind project ...... 32

Table 10 JEDI cost model – Energy 2035 plan scenario (180 MW)...... 33

Table 11 JEDI benefit model – Energy 2035 plan scenario (180 MW)...... 34

Table 12 JEDI cost model – Scenario 1 (198 MW)...... 35

Table 13 JEDI benefit model – Scenario 1 (198 MW)...... 36

Table 14 JEDI cost model – Scenario 2 (216 MW)...... 37

Table 15 JEDI benefit model – Scenario 2 (216 MW)...... 38

Table 16 JEDI cost model – Scenario 3 (234 MW)...... 39

Table 17 JEDI benefit model – Scenario 3 (234 MW)...... 40

Table 18 Levelized cost of energy comparison...... 41

Table 19 Levelized avoided cost of energy comparison...... 43

Table 20 Net value results of expanded BIWF...... 44

Table 21 Internal rate of return comparison for expanded BIWF...... 45

xi Table 22 Net present value of expanded BIWF ...... 46

Table 23 Consumer price comparison...... 47

Table 24 Emissions comparison...... 48

Table 25 Cost of mitigation comparison...... 48

Table 26 NREL estimated LCOE ranges by U.S. regions...... 52

Table 27 BIWF cash flow...... 57

Table 28 Energy 2035 baseline (180 MW) cash flow with Deepwater Wind data...... 61

Table 29 Energy 2035 baseline (180 MW) cash flow with JEDI model data...... 63

Table 30 Energy 2035 baseline (180 MW) cash flow with EIA data...... 65

Table 32 Scenario 1 (198 MW) cash flow with JEDI data...... 69

Table 33 Scenario 1 (198 MW) cash flow with EIA data...... 71

Table 34 Scenario 2 (216 MW) cash flow with Deepwater Wind data...... 73

Table 35 Scenario 2 (216 MW) cash flow with JEDI data...... 75

Table 36 Scenario 2 (216 MW) cash flow with EIA data...... 77

Table 37 Scenario 3 (234 MW) cash flow with Deepwater Wind data...... 79

Table 38 Scenario 3 (234 MW) cash flow with JEDI model data...... 81

Table 39 Scenario 3 (234 MW) cash flow with EIA data...... 83

xii List of Figures

Figure 1 Expected IRR for wind projects...... 4

Figure 2 Rhode Island electricity usage and expenditures, 2010...... 7

Figure 3 United States offshore wind power pipeline, 2015 ...... 11

Figure 4 WEA zones, Rhode Island & Massachusetts ...... 12

Figure 5 Comparison of levelized costs, government interventions, and external costs for energy sources in Europe...... 15

Figure 6 Impact of turbine size on project cost...... 54

xiii

Definition of Terms

BIWF (Block Island Wind Farm): The site of the Deepwater Wind project. Located just off the coast of Block Island, Rhode Island.

BOEM (U.S. Department of the Interior’s Bureau of Ocean Energy Management): Bureau responsible for overseeing authorization and leasing of United States ocean zones for energy generation or procurement.

Capacity Credit: The probability that an intermittent source of energy will reliably provide energy. For example, the capacity credit of a wind turbine may be assigned as ≥ 1% - ≤ 100% depending on the consistency of wind flows.

Capacity Payment: Denotes the value that a system gives to meeting a reliability reserve margin; this is the payment that an energy system would theoretically need in order to provide the last unit of capacity to meet a reliability reserve requirement (United States Energy Information Administration, 2013).

CM (Cost of Mitigation): The cost of reducing CO2 pollution when comparing two sources of energy. In this thesis, the cost of mitigating CO2 pollution from natural gas plants by switching to offshore wind will be measured.

Energy 2035: The Rhode Island Division of Planning’s plan for energy generation, procurement, and consumption, published in 2015. The plan aims to increase the security, cost-effectiveness, and sustainability of Rhode Island’s energy for electrical, thermal, and transportation applications.

ITC (Investment Tax Credit): Tax credit on investment expenditures for renewable energy projects. Currently, offshore wind projects are not eligible for an income tax credit, but for a production tax credit. The production tax credit is set to expire in 2020, and bills are proposed to extend the production tax credit. This thesis uses the current levels of production tax credits adjusted for 2022 ($14/MwH) as an assumption for a future investment tax credit.

xiv JEDI (Jobs and Economic Development Index): Analyzes the microeconomic impact of a given project on the local economy; includes measurements of onsite labor impacts, local revenue, supply chain impacts, and induced impacts of project construction.

LACE (Levelized Avoided Cost of Energy): Used to estimate costs of generating renewable energy in direct comparison with the cost of generating energy from another source. In this case, energy generated from offshore wind will be compared with natural gas, Rhode Island’s current predominant source.

LCOE (Levelized Cost of Energy): A measure of cost-competitiveness of energy sources; LCOE provides the net present value of unit costs of energy with the goal of providing a lifetime analysis of cost. LCOE is crucial in comparing costs of renewable and traditional energy sources to consumers.

Marginal General Price: The cost of meeting energy load demand, typically comprised of fuel costs and variable operations and maintenance costs. Marginal generation price can also be calculated including subsidies or credits; this thesis will not incorporate direct government incentives into marginal generation price.

NREL (National Renewable Energy Lab): A national laboratory under the U.S. Department of Energy, Office of Energy Efficiency & Renewable Energy. NREL is operated by the Alliance for Sustainable Energy, LLC.

PPA (Power Purchase Agreement): An agreement between an energy producer and provider of electricity to lock prices in at a mutually agreed-upon level. In the case of Deepwater Wind, this price was $212.63 per megawatt hour, with a 3.5% escalation each year.

RES (Renewable Energy Standard): The mandatory minimum amount of energy procured from renewable sources. The Energy 2035 plan outlines a goal of 40% RES for Rhode Island by 2035, with roughly a 1.5% increase each year.

RIDOP (Rhode Island Division of Planning): Rhode Island government department responsible for evaluating needs of the state and prescribing solutions, especially infrastructure, to adequately meet state needs. Energy falls under RIDOP’s evaluation jurisdiction.

xv RIOER (Rhode Island Office of Energy Resources): Rhode Island department responsible for planning supply of and access to energy resources. This same department manages public-private partnerships for energy projects and works to stabilize energy prices for Rhode Island consumers.

WEA (Wind Energy Area): Areas deemed fit for housing of offshore wind energy projects by BOEM. Designation of WEAs includes analysis of bathymetry, wind speed, shipping traffic zones, and wildlife protection areas.

xvi

Chapter I

Introduction

In an effort to improve energy security, cost-effectiveness and sustainability,

Rhode Island is in the process of reforming its system of energy production and procurement. A 2015 plan by the Rhode Island Division of Planning entitled "Energy

2035" presents detailed goals for the state’s energy system, including a mandatory minimum of renewable energy procurement called a “Renewable Energy Standard”

(RES).

Rhode Island's RES is currently set at 16% of total energy usage, Energy 2035 outlines a target of 40% RES for 2035. It is projected that this plan will yield over $8 billion (net present value) in economic benefits (Rhode Island Department of

Administration, Division of Planning, 2015). The plan includes three scenarios for satisfying specific emissions and economic targets; all three scenarios are contingent on

180 megawatts (MW) of energy coming from offshore wind power (Rhode Island

Department of Administration, Division of Planning, 2015) (Table 1). However, located

9.2 nautical miles off the coast of Rhode Island are 164,750 acres capable of supporting a utility-scale wind farm (with interpolated wind speeds of more than eight meters per second at 80 meters above sea level) (Rhode Island Department of Administration,

Division of Planning, 2015). It is estimated that this area could produce three gigawatts

(GW) of energy, enough to power one million homes, exceeding demand in Rhode Island

1 by a factor of 2.5. Additionally, with the infrastructure already in place at the BIWF, it is conceivable that this project could be expanded to satisfy or exceed the 180 MW goal.

Table 1. Energy 2035 proposed target increase scenarios (Rhode Island Department of Administration, Division of Planning, 2015).

Currently, five offshore wind turbines with a total production capacity of 30

(MW) are under operation off the coast of Rhode Island. The current offshore wind project, a privately funded facility called the Block Island Wind Farm (BIWF), has gained modest investment; one reason for this is that the price of energy generated from offshore energy is presently more expensive than energy generated from natural gas. For the BIWF to be successful long-term, the business case for offshore wind energy needs to be strengthened. A 2015 analysis by Navigant consulting found that capital expenditures

(net present value) for the sustainable energy scenarios put forth in Energy 2035 could outweigh economic benefit by 2035 (Navigant Consulting, 2015). However, this analysis

2 does acknowledge the likelihood that improved technologies (such as energy storage) will decrease costs associated with renewable energy.

Research Significance and Objectives

I propose that increasing the targets for energy generated by offshore wind power facilities in the three scenarios proposed under the "Energy 2035" plan may significantly increase the end economic output of the plan. An expanded market would provide better opportunities for Deepwater Wind to expand the current operation within the high- velocity wind zone and offer more energy to electric grids. Furthermore, increasing offshore wind energy targets may create a better market for renewable energy in Rhode

Island, making renewable energy sold to utility companies more profitable, and as a result, offshore wind will be a less risky area for capital investment. A larger wind farm has potential to make better use of fixed costs and operations and maintenance expenditures, making the project more cost-effective. Additionally, creation of full-time jobs and increases in tax revenue for the state may also exceed estimates included in the original plan. A power purchase agreement (PPA) is currently in place, which prevents prices for consumers from rising too drastically. However, with a lower cost of generation comes an opportunity to sell at lower prices to consumers while maintaining profits, the LCOE and breakeven price calculations incorporated in this thesis serve as a means of understanding how the lower limits of profitability may change in an expanded project.

The main objective of this thesis is to deconstruct the pricing projections used in

Navigant Consulting’s report and re-approach the potential of the Energy 2035 plan.

Three scenarios are proposed, involving new targets for wind power, set 10%, 20%, and

3 30% higher than those currently included in the plan, thereby exploring hypothetical mandatory minimums for wind power of 198 MW, 216 MW, and 234 MW.

A Deloitte analysis states an expectation of 6%- 7.5% IRR for operating offshore wind plants (Deloitte, 2014) (Figure 1).

Figure 1. Expected IRR for wind projects (Deloitte, 2014).

In the testimony of former Deepwater Wind CEO to the Rhode Island State Public

Utilities Commission, an expected IRR of 9.66% was stated for the BIWF (State of

Rhode Island Public Utilities Commission, 2010). In exploring the hypothetical expansion of the BIWF to sizes of 180 MW, 198 MW, 216 MW, and 234 MW, the IRR and NPV of each scenario will be compared to those of the current BIWF as well as reported averages from offshore wind farms already in operation. The results of these calculations will add comment on the possibility of offshore wind energy generated at

4 BIWF to be economically competitive for consumers, as well as providing a structured approach to analyzing the investment case for future expansions.

Background

The United States is in the midst of a struggle to combat the detrimental effects of fossil fuel usage. An over reliance on fossil fuels to achieve industrial and transport efficiency has left the world’s largest economy in a position of vulnerability, as environmental and health complications resulting from climate change now threaten the populace. Despite the new imperative to shift reliance on fossil fuels to a system that better incorporates renewable energy, the U.S. has been slow to create better energy sources for consumers, largely as a result of market conditions that favor fossil fuels and thus make renewable energy a risky business proposition.

In particular, the United States has yet to make use of its vast coastline areas to implement offshore wind farms in areas that have the strongest wind flows. There are currently no operational offshore wind farms on U.S. coasts, although small pilot projects are under construction off the coasts of Rhode Island and New Jersey. Rhode Island, like most U.S. states, has ambitious goals for renewable energy procurement, but lacks sufficient energy generation sources and therefore is unable to set higher renewable energy goals. Most of Rhode Island’s energy is procured from other states, making price stability a crucial issue to Rhode Island citizens (Rhode Island Department of

Administration, Division of Planning (RIDOP), 2015).

5 Rhode Island’s Energy 2035

Energy 2035 was put forth in order to guide the policies of the Rhode Island

Office of Energy Resources (RIOER) and the RIDOP with regard to energy generation, procurement, and consumption through the year 2035. Energy 2035 presents three overarching goals, under which fall detailed sub-goals, that the plan intends to achieve: improvement of energy security, increase in energy cost-effectiveness, and “sustainability in all sectors of energy production and consumption” (Rhode Island Department of

Administration, Division of Planning, 2015). Pursuit of these three goals is approached within three energy sectors: thermal, transportation, and electricity. Currently, the majority of energy within all three sectors is supplied via fossil fuel sources including natural gas, oil, distillate fuel, and other petroleum products (Rhode Island Department of

Administration, Division of Planning, 2015).

In 2010, Rhode Island consumed roughly 190 trillion BTU of energy in total, with consumption split nearly equally between electricity, thermal, and transportation (63 trillion BTU, 63 trillion BTU, and 64 trillion BTU respectively) at a total cost of $3.6 billion and an emissions total of 11 million tons of CO2 (Rhode Island Department of

Administration, Division of Planning, 2015). The chart below (Figure 2), from RIDOP, details the consumption, cost, emissions, and energy source by sector in 2010. Rhode

Island’s electricity generation sector is heavily reliant on the use of natural gas, comprising 98% of primary energy sources, with landfill gas the remaining 2% (Rhode

Island Department of Administration, Division of Planning, 2015).

Figure 2. Rhode Island electricity usage and expenditures, 2010 (Rhode Island Department of Administration, Division of Planning, 2015).

Of the reliance on fossil fuels by Rhode Island’s energy sectors, Energy 2035 states:

Growing concerns about the security, cost, and sustainability impacts of energy use have placed energy issues on the forefront of Rhode Island’s public policy agenda over the past two decades. In recognition of the central role that energy plays in shaping the state’s communities, economy, and environment, policy makers have enacted ambitious energy policies and programs, primarily in the areas of energy efficiency and renewable energy” (Rhode Island Department of Administration, Division of Planning, 2015).

Rhode Island’s Energy Supply

Rhode Island is able to procure only negligible amounts of energy from sources within the state. The RIDOP states that the most significant energy supply resources in

Rhode Island are energy savings that are achieved through investments in energy efficiency, but beyond energy efficiency the state is almost entirely dependent on fossil fuels imported from outside of state borders (Rhode Island Department of

Administration, Division of Planning, 2015). The fossil fuels that Rhode Island imports

7 come from both regional and international supply sources in the forms of a natural gas pipeline system and shipments of petroleum (Rhode Island Department of

Administration, Division of Planning, 2015).

Up until this point, Rhode Island has used policy levers to ensure lower energy prices for consumers by enforcing a system of “Least-Cost Procurement” for electric and gas distribution companies (Rhode Island Department of Administration, Division of

Planning, 2015). These policies mandate that energy distributors invest in the most efficient and cost-effective demand reduction tactics, including high-efficiency lighting,

HVAC systems, insulation, air-sealing, and more (Rhode Island Department of

Administration, Division of Planning, 2015). Least-Cost Procurement strategies have contributed to what has been a largely successful effort in increasing energy efficiency; by the year 2013, the past 10 years of energy efficiency programs had yielded 12% cumulative savings on energy consumption (Rhode Island Department of Administration,

Division of Planning, 2015).

Rhode Island’s electricity supply is largely routed through a large regional electrical grid. 99% of Rhode Island’s electricity customers purchase from National Grid,

National Grid serves approximately 486,000 households in Rhode Island (Rhode Island

Department of Administration, Division of Planning, 2015).

Rhode Island’s heavy reliance on natural gas creates potential for price volatility in the coming decades; therefore, it has been determined by RIDOP and other state bodies that energy diversification is critical to maintaining stable pricing for consumers

(ISO New England, 2014). Furthermore, the state has determined a goal of committing to renewable energy in an effort to reduce net emissions and curb long-term health effects

8 on citizens. The renewable energy standard (RES) is a mechanism put in place to mandate minimum procurement levels of renewable energy for Rhode Island’s electrical grids. By setting an RES, the state has created a market for renewables that signals to developers the desire of the state to welcome more renewable energy projects and to the grids an expectation that fossil fuels be gradually phased out in favor of renewable energy sources (ISO New England, 2014).

Offshore Wind in the United States

Wind power, as opposed to competing modern sources of energy such as oil or coal, is heavily dependent on the geographic placement of facilities. The amount of energy generated rests entirely on the velocity of wind within the cube that a wind turbine is able to capture; a doubling of a given wind velocity will result in eight times (23) as much energy generated as a tripling in velocity will yield 27 times (33) as much energy

(Timmons, Harris, & Roach, 2014). Intermittency of wind speeds is a constraining factor in planning profitable wind power projects, as there is little guarantee in the consistence of speeds; turbine sites must offer high and consistent wind velocities to be economical.

A good wind site typically has a capacity factor of only 30%, whereas competing nuclear and coal plants meet or exceed capacity factors of 90% on average (Timmons, Harris, &

Roach, 2014).

Nonetheless, offshore wind offers benefits that onshore wind cannot. Offshore wind facilities are located in oceans and lakes, and therefore not obstructing residential or commercial areas. The location of offshore wind facilities at considerable distances from homes and businesses allows for fewer difficulties associated resulting from acoustic disruption. Additionally, coastal areas offer densely concentrated areas of high-velocity

9 winds, where groups of turbines numbering in the hundreds can be constructed, reducing costs to deliver energy to users and costs associated with operations and maintenance.

Offshore wind has been included in proposals and project pitches in the coastal

United States for over two decades; however, no offshore wind farms are in operation at the time of writing (Deepwater Wind will not operate until 2017). This statistic is significant when compared to the progress of European projects within the same two- decade time frame; as of 2014 nearly, 65 offshore wind farms were operating off of

Europe’s coasts (Timmons, Harris, & Roach, 2014). The Energy Information

Administration states that the U.S. coastal and Great Lakes regions have potential to provide nearly 4.15 terawatts (TW), an amount that exceeds the nation’s total electric generating capacity in the year 2009 (Timmons, Harris, & Roach, 2014).

Approximately 15,650 MW of offshore wind projects are in various stages of development in 2015 (Figure 3) within the United States (Smith, Stehly, & Musial,

2015). Of these projects, approximately 3,305 MW have stated an intention to be operational by 2020, while a U.S. Department of Energy plan entitled “Wind Vision” predicts deployment of 22,000 MW and 86,000 MW respectively by 2030 and 2050

(Smith, Stehly, & Musial, 2015).

Figure 3. United States offshore wind power pipeline, 2015 (Smith, Stehly, & Musial, 2015).

Potential to develop offshore wind capacity is critical in the United States also because the abundance of high-velocity wind zones creates conceivable scenarios for displacement of fossil fuels as primary energy sources. The U.S. Department of Energy has stated that each MW of offshore wind power can replace nearly 5,500 barrels of oil per year, or around 26 million cubic feet of natural gas (Parker, 2010). Such a considerable displacement of fossil fuels will result in drastically reduced emissions and public health risks associated with air pollutants.

Offshore Wind Potential in the Block Island Sound

While Rhode Island currently depends mostly on fossil fuel-generated electricity imports, there remains great potential for expansion of indigenous and renewable energy through the harnessing of offshore wind capacity. Off the coast of Block Island, Rhode

11 Island lies a large ocean area with sustained high-speed winds. This same area is flanked by shipping lanes, with space for maritime traffic available on either side (Figure 4).

Figure 4. WEA zones, Rhode Island & Massachusetts (Musial, Elliott, Fields, Parker, & Scott, 2013).

This area is capable of housing hundreds of wind turbines, and gained approval for development in 2013. A 2009 study conducted by NREL found strong density of high-speed wind zones, which the study separated into North and South zones (labeled in yellow and green, respectively, in Figure 4). NREL concluded that both zones could each support offshore wind project development with a capacity of over 1,000 MW (Musial et al., 2013). Specifically, the study stated that the North zone has a maximum capacity of

12 1,955 MW and the South zone a maximum capacity of 1,440 MW, enough capacity for a wind farm of 679 turbines to generate 3,395 MW (Table 2), an amount equal to more than 80% of Denmark’s entire installed capacity (Musial et al., 2013).

Table 2. North and South Zone offshore wind capacity (Musial et al., 2013).

Previous Attempts at Offshore Wind Projects in the Atlantic

There have been multiple attempts at offshore wind projects in the Atlantic Ocean in the recent two decades, the most notable of which has been Cape Wind, a proposed, but never fulfilled, project off the coast of Cape Cod, Massachusetts. Cape Wind was originally proposed in the year 2001, received permits in 2011, yet never made it into construction as a result of weak regulatory framework and persistent opposition from residents. Cape Wind was originally intended to combine 130 turbines with a capacity of

3.6 MW each for a total capacity of 468 MW, enough to provide electricity for at least

75% of Cape Cod and the closest islands (Timmons, Harris, & Roach, 2014). In 2012,

Cape Wind secured a contract with National Grid to sell energy from the offshore wind

13 farm for $0.187/KWh; at the time, this rate was substantially more expensive than energy generated from other sources Timmons, Harris, & Roach, 2014).

Despite gaining permits for the initial 468 MW, Cape Wind has still yet to break ground. Although there was some public opposition stemming from the affordability of the energy that the project would generate, the strongest opponents were local Cape Cod residents that objected to the projects on the grounds that they believed the appearance of the turbines off the coast to be aesthetically displeasing and detrimental to the property value of their homes. Proponents of the opposition included members of the Koch and

Kennedy families, who own multi-million dollar homes in Cape Cod.

Cape Wind, although unsuccessful, is a relevant and important case to examine in order to understand the potential of Deepwater Wind. It is worth noting that while Cape

Wind was never ultimately successful, most legal hurdles were indeed cleared, and the argument against construction on grounds of property-devaluation have already been overcome in Block Island. Still, it is important to recognize that both communities (Cape

Cod and Block Island) are comprised of largely affluent homeowners, with median incomes considerably above that of the average community and with residents for whom savings on electricity cannot conceivably outweigh potential loss in property value. For the majority of communities that stand to benefit from the price stability that offshore wind could create, the turbines will be far out of sight and the benefits as consumers will be tangible.

Offshore Wind Policy in Europe

Offshore wind is much more prevalent in the European Union than in the United

States, with over 65 offshore wind projects already in operation. Europe’s success in

14 implementing offshore wind has relied on a combination of government initiative to mandate shifts away from fossil fuels, continued subsidization of renewable energy projects, and promulgation of power purchase agreement (PPA) that stipulate pricing requirements for energy sold from generation plants to electrical grids. Policy interventions contribute a significant amount toward cost reduction for offshore wind in

Europe (Figure 5), on average accounting for 90% of levelized costs. These contributions, combined with aggressive PPAs allow renewable energy companies to finance more of their projects on debt and to mitigate risk for investors. In evaluating intervention options, European governments are typically incorporating costs of externalities, as an example, the external costs of coal can be seen in the figure below as meeting or exceeding levelized costs of energy generation from coal.

Figure 5. Comparison of levelized costs, government interventions, and external costs for energy sources in Europe. (Alberici, 2014).

In 2012, nearly €1.4 Billion in subsidies were allocated to offshore wind

(Alberici, 2014) (Table 3). While this amount is likely low due to the number of projects

15 under operation that are able to receive these subsidies, it is unlikely to ever reach the level of subsidies that coal and natural gas currently rely on. The specific measures that make up the 2012 figures below include €60 million in grants, €340 million in feed-in premiums, €80 million in feed-in tariffs, €870 million in renewable energy quotas with tradeable certificates, and €10 million in R&D grants (Alberici, 2014).

Table 3. Government support per technology in Europe (includes GHG credits) (Alberici, 2014).

Deepwater Wind

In 2013, after legislative proceedings determined that the area of the coast of

Block Island would be approved for an offshore wind operation, the first project was

16 awarded to a company by the name of Deepwater Wind. Deepwater Wind is the first offshore wind farm to make use of the high-velocity winds found off the shore of Block

Island, Rhode Island. The Deepwater Wind project, under construction now, is privately funded and has been approved for operation by the Rhode Island legislature. Currently, five offshore wind turbines with a production capacity of 30 MW are under construction off the coast of Rhode Island. 30 MW is an underwhelming output, given that the designated area off the coast of Block Island has potential to house a wind farm with capabilities of near three gigawatts (GW). In real output, the current project will provide energy to 15,000 homes, whereas the full potential of the area, if exploited, would provide energy to 1.5 million households. In theory, the designated offshore wind zone off the coast of Block Island would only need to be used to half its capacity to satisfy

Rhode Island’s energy needs. It is likely that the success or failure of Deepwater Wind will be regarded as a template for U.S. offshore wind farms in coming policy decisions.

At the time of writing, Deepwater Wind had secured $290 in a mix of tax equity and debt funding from Société Générale of France and Keybank of Cleveland (Deepwater

Wind, 2015).

Deepwater Wind Power Purchase Agreement

In 2010, a power purchase agreement (PPA) was negotiated between Deepwater

Wind and National Grid. After negotiations, it was agreed upon that the price of energy sold from Deepwater Wind to National Grid would not exceed $235.70 per MWh in the first year, with a 3.5% escalation each year thereafter (Rhode Island Public Utilities

Commission, 2010). This agreement stipulates that Deepwater Wind is only able to charge National Grid for energy that is actually provided. This agreement allows

17 Deepwater Wind to maintain steady levels of profits throughout project lifetime, while ensuring that rates remain steady for consumers and any savings on the costs of the Block

Island Wind Farm (BIWF) are passed on to consumers.

It is important to recognize that Block Island’s electricity has typically been supplied via diesel generators. Therefore, the electricity from offshore wind provided by

BIWF does indeed provide some cost relief for residents. However, in the case of a larger project, the prices under the current PPA would be more expensive than options already available for Rhode Island residents.

Environmental Impacts of Deepwater Wind

A 2014 National Oceanic and Atmospheric Administration (NOAA) report explored the potential effects of Deepwater Wind on marine life and ecosystems in the high-velocity wind zone. The main concerns surrounding operation of offshore wind facilities involve disruption of marine life and birds resulting from acoustic effects of wind turbines. Additional concerns exist regarding potential for the release of marine debris and fuel spills from maintenance vessels. The report concluded that acoustics from turbines would remain below the decibel threshold that constitutes harassment of marine animals (National Oceanic and Atmospheric Administration, 2014). The report also found that fuel spills from maintenance ships, while potentially dangerous to the surrounding ecosystem, were unlikely to be substantial enough to disrupt ecosystems and would instead be concentrated in a small area and could be addressed quickly before spreading (National Oceanic and Atmospheric Administration, 2014). Overall, the report concluded that operation of Deepwater Wind “would not be expected to result in a cumulative significant impact to the human environment from past, present, and future

18 activities” and “Potential impacts to marine mammals, their habitats, and the human environment in general are expected to be minimal based on the limited and temporary footprint and mitigation and monitoring requirements of the Authorizations” (National

Oceanic and Atmospheric Administration, 2014).

Block Island Wind Farm Financial Analysis

During Rhode Island Supreme Court proceedings to decide on the BIWF PPA,

Deepwater Wind was required to reply to multiple requests for data. Included in these requests were predicted cash flows (Table 4) for each year of the project lifetime as well as approximate calculations on project cost and the predicted CAPEX and O&M. These disclosures were used as a basis for the Rhode Island Supreme Court to decide whether the PPA prices proposed by Deepwater Wind were reasonable in relation to project costs.

19 Table 4. Block Island Wind Farm cash flow during construction (State of Rhode Island Public Utilities Commission, 2010).

This research used the CAPEX and cash flow figures, in conjunction with prices agreed upon in the PPA, to establish a baseline of cost and profitability for the project. A third-party analysis performed by Rhode Island-based Levitan & Associates provides a breakdown of predicted project costs necessary to complete construction of the BIWF

(Table 5). Later in this thesis, the Levitan & Associates prediction serves as a baseline figure for comparisons between the CAPEX predictions generated in this thesis and those assumed during the BIWF PPA process.

20 Table 5. Block Island Wind Farm project cost estimate (Parker, 2010).

The assessment by Levitan & Associates also incorporates a prediction of contributions to the Rhode Island GDP from the BIWF (Table 6).

Table 6. Block Island Wind Farm contribution to RI GDP (Parker, 2010).

21 Proposed Economic Outcomes of Energy 2035

It is projected that the Energy 2035 plan will yield over $8 billion (net present value) in economic benefits (Rhode Island Department of Administration, Division of

Planning, 2015). Economic benefits as defined in this model are constituted by jobs added to the local economy, tax revenue, and savings to consumers that yield higher disposable incomes and thus more spending and business revenue within the local economy. Offshore wind offers a unique opportunity to accelerate receipt of economic benefits by creating more local projects. Moreover, an increase in local projects will yield higher demand for workers to staff operations.

A 2012 report by Lawrence Berkeley National Lab found that the average cost to

Rhode Island energy consumers resulting from the RES charge was approximately

.00182¢/KWh in 2012, raising electricity rates for residential consumers by about $1.08 per month (Heeter et al., 2014). An estimated 12% rate increase in natural gas prices by the same report would increase residential consumer costs by roughly $10/month (Heeter et al., 2014). It has also been reported that RES targets have produced positive results in prior cases: utility-scale solar projects have dropped in price by 70% since 2008 and the price of utility-scale wind projects have dropped by over 50% in a similar period

(Cardwell, 2014).

A 2015 analysis by Navigant Consulting found that capital expenditures (net present value) for sustainable energy projects could outweigh economic benefit by 2035; however, this analysis did not take into account any change in energy pricing between

2015 and 2035. This thesis explores the costs and benefits of an expanded mandatory minimum for renewable energy procurement by electrical grids, referred to as a

22 renewable energy standard (RES) target, and the ways in which the BIWF can grow under expanded targets, and the resulting benefits to investors and consumers from expanded targets.

Research Questions, Hypothesis, and Specific Aims

The research described in this proposal will seek to answer two critical questions, both related to the ability of energy policy to create markets for offshore wind. The first question is whether Rhode Island’s RES can effectively increase the profitability of the

BIWF project, provided that improved markets beget expansion of the project. This is addressed by modeling three scenarios of targets increased by 10%, 20%, and 30%, examining key variables. The hypothesis I test is that the profitability of the project can be increased by as much as 20%.

The second question to be answered by this research is whether further investment in the Deepwater Wind project can make electricity generated from offshore wind a competitive option in the market. To evaluate this, thorough levelized cost of energy

(LCOE) and levelized avoided cost of energy (LACE) calculations will examine lifecycle costs of offshore wind as compared to those of natural gas. I predict that energy generated from an expanded BIWF can break even at a level below the average cost per kilowatt hour (KWh) for Rhode Island customers of 16.95 cents, and the 17 annual long term jobs created by the current BIWF can exceed 50.

Chapter II

Methods

To address the question of whether Rhode Island’s RES can effectively increase the profitability of the BIWF project, three scenarios of targets increased by 10%, 20%, and 30% were examined. The key variables in the modeling included project CAPEX, operations and maintenance (O&M), and overall cost of energy generation (LCOE and

LACE). The metrics for measurement included IRR, NPV, and cost of mitigation.

Full cash flow projections were constructed for each hypothetical scenario, using the three data sources and maintaining the purchasing price from the latest PPA

(continuing a 3.5% increase per year). The potential impact of an investment tax credit

(ITC) was incorporated using ITC schemes scheduled to be implemented for renewable energy plants constructed in 2022. Each cash flow analysis included a comparison of free cash flows and profit margins with and without the ITC. The appendix presents the full cash flow from each scenario.

In order to construct the hypothetical expanded BIWF wind farm, three data sources were used to measure the potential costs and benefits. The first data source consists of an assumption of cost and investment values from the current BIWF cash flow predictions outlined in the Moore Testimony (see Table 27 in the Appendix for full cash flow). This cash flow identifies expected capital expenditures (CAPEX), operations and maintenance (O&M), depreciation, and tax liabilities. A data source was created for expansion scenarios by extrapolating CAPEX and O&M values per MW generated.

Additionally, the predicted depreciation of the BIWF CAPEX was applied to all cash

24 flow calculations. The second data source is generated using a JEDI model. The JEDI model, developed by the National Renewable Energy Laboratory, uses inputs based on technology specifications, project life, funding mechanisms, state laws, and wind consistency trends to generate predicted CAPEX, O&M, and financing costs in addition to estimating jobs and economic benefits for the local economy. The third data source consists of average CAPEX and O&M costs per MWh for offshore wind projects compiled from EIA data.

The product of this research consists of two parallel benefit-cost analysis (BCA) calculations: BCA for investors and BCA for the State of Rhode Island. Both analyses took into account the economic benefits of expanded targets, positive or negative, versus those of the status quo. The first BCA analyzed the ability of offshore wind energy to break even under the hypothesized targets. The second BCA, of equal importance, assessed the potential profitability of the Deepwater Wind project given higher offshore wind targets. This assessment affects the likelihood that the project will be able to gain more substantial investment and undertake an expansion using the current system and technology employed at the Block Island Wind Farm.

The first stage of this research explored the impacts on the local economy in terms of jobs created by the project, jobs lost in other energy sectors, savings to consumers (to be spent elsewhere in the economy), and negative effects on property value. These factors were weighed with the use of a jobs and economic development index (JEDI) model. The

JEDI model is a tool developed by NREL to measure the impacts of new energy projects on local communities by estimating three types of outcomes: money spent on labor for on-site construction, revenues gained by local supply chains and supporting industries,

25 and the overall GDP value added through reinvestment and spending of earnings

(National Renewable Energy Laboratory, 2015). JEDI models are an efficient tool for measuring local economic impacts of energy projects, as they use detailed state data, derived from the Minnesota IMPLAN Group, in conjunction with variables such as project size, construction period length, capacity factor, project lifecycle, type of technology (including models of plant equipment), and financing mix (equity, debt, etc.) to create predictions within realistic parameters.

The JEDI model allows for a baseline prediction of net effects on the local economy including value added from construction and onsite labor earnings, technology and supply chain outputs, local revenue outputs, and induced outputs.

Evaluating Cost and Profitability

The advantages of the expanded project under the three new scenarios were measured through a combination of levelized cost of energy (LCOE) and levelized avoided cost of energy (LACE). LCOE was used to indicate the costs of offshore wind under the increased RES scenarios and over the time horizon of the project. LCOE calculations examined the discounted costs of fixed mechanicals, fuel, and variable costs at any given stage in the project. The equation is given below:

퐼 + 푀 + 퐹 ∑푛 푡 푡 푡 푡=1 (1 + 푟)푡 퐿퐶푂퐸 = 퐸 ∑푛 푡 푡=1 (1 + 푟)푡

퐼푡 = Investment expenditures in year t 푀푡 = O&M costs in year t 퐹푡 = Fuel expenditures in year t 퐸푡 = Electricity generation in year t r = Discount rate

26 n = Life of system

The analysis also made use of LACE calculations to indicate the potential revenue of the project under the new scenarios, weighting the average marginal cost of dispatch during times of operation by the expected amount of operation hours. (United States

Energy Information Administration, 2013). The importance of exploring an avoided cost of energy is explained by the EIA:

Conceptually, a better assessment of economic competitiveness can be gained through consideration of avoided cost, a measure of what it would cost the grid to generate the electricity that is otherwise displaced by a new generation project, as well as its levelized cost. Avoided cost, which provides a proxy measure for the annual economic value of a candidate project, may be summed over its financial life and converted to a level annualized value that is divided by average annual output of the project to develop its “levelized” avoided cost of electricity (LACE)” (EIA, 2017).

In order to assess a likely capacity credit and capacity payment avoided by opting for either offshore wind or combined-cycle natural gas, the cost of an advanced natural-gas fired combustion turbine plant was used as the de facto capacity payment ($682 / kW) and capacity credit (25%) (Beiter, Musial, Kilcher, Maness, & Smith, 2017). LACE is calculated as:

∑푌 (퐺푃 ∗ 퐷퐻 ) + (퐶푃 ∗ 퐶퐶) 퐿퐴퐶퐸 = 푡=1 푡 퐻

GP - Annual marginal general price DHt – Dispatched hours H - Annual expected general hours 퐶푃 – Capacity payment 퐶퐶 - Capacity credit t – time period Y – Amount of time periods in a year

27 NREL recommends determining a project’s economic potential by deriving a net value from the difference in LACE and LCOE. When using a net value calculation with

LACE and LCOE, a result greater than zero is meant to indicate economic viability.

푁푒푡 푉푎푙푢푒 = 퐿퐴퐶퐸 − 퐿퐶푂퐸

The three scenarios were checked against a breakeven price (BP) calculation to understand the minimal price at which energy generated from this particular project may be competitive with natural gas. Breakeven price is calculated as:

푛 ∑ 퐶푓 퐵푃 = 푖=0 퐶푣 푃 − 푃

퐶푓- Fixed cost of a unit 퐶푣 - Variable cost of a unit P – Price

Understanding the current state of profit potential of offshore wind involved incorporating traditional accounting methods into the model, in addition to energy- specific measurements. The benefit of including traditional accounting methods is to understand profit potential before including externalities in the calculations. In order to analyze these projects over a full lifecycle time horizon, a combination of IRR and NPV was used. The equations used for NPV and IRR calculations were:

푇 퐶 푁푃푉 = ∑ 푡 − 퐶 (1 + 푟)푡 0 푡=1

퐶푡 = Cash flow of the project at year t 퐶0 = Construction cost

푁푃푉푎 퐼푅푅 = 푟푎 + (푟푏 − 푟푎) 푁푃푉푎 − 푁푃푉푏

28 푟푎 = Lower discount rate chosen 푟푏 = Higher discount rate chosen 푁푃푉푎 = NPV at 푟푎 푁푃푉푏= NPV at 푟푏

In order to quantify the cost and benefit of displacing the emissions created by natural gas by opting for offshore wind, a cost of mitigation calculation was included.

The cost of mitigation calculation involved first measuring the amount of emissions generated from natural gas electrical plants and offshore wind plants, and then calculating the difference in cost between electricity from offshore wind and natural gas for the same amount of megawatt hours. The cost difference was then divided by the pollution difference, which, in this case, consisted only of the amount of pollution generated by natural gas plants. Cost of mitigation was calculated as:

퐶 − 퐶 푐 푑 푃푑 − 푃푐

퐶푐 = Cost of clean option 퐶푑 = Cost of dirty option 푃푐 = Pollution of clean option 푃푑 = Pollution of dirty option

Chapter III

Results

Results in Table 7 below list the estimated capital expenditures (CAPEX) for every scenario of the project, from the baseline of the current 30 MW to the fulfillment of a 180 MW offshore wind renewable energy standards (RES) with an expanded BIWF project and the three scenarios utilizing a more substantial RES. It can be seen from the initial estimates that the data generated from the JEDI model are relatively consistent with that provided by Deepwater Wind in the Moore Testimony for the 30 MW BIWF that was presented earlier in Table 4.

Table 7. Average MWh per year and CAPEX for five scenarios.

A JEDI model calculation run for the current BIWF (30 MW) (Table 8), returns a

CAPEX amount of just over $206 million, compared to the Deepwater Wind estimates of around $205 million. Furthermore, an analysis prepared by a third party for the Rhode

Island Economic Development Corporation also using the IMPLAN model with data provided directly by Deepwater Wind adds comment on the usefulness of the JEDI model in assessing this case. The closeness in results offers an interesting observation, as later in

30 the calculation results the JEDI model consistently predicts the lowest cost and highest profit scenarios.

Table 8. JEDI cost model – current Block Island Wind project.

According to projections in the JEDI model, the majority of economic benefits are derived during the project construction phase, which is estimated to create nearly 685 full time jobs and generate an economic output of nearly $130 million. During operating years, the project is estimated to require around 16 full time jobs and generate around $3 million in output. Interestingly, the direct effects (“Subtotal Project Development and

Onsite Labor Impacts” in Table 9) of $55.94 million is comparable to the $55 million in

31 Table 6 earlier, and the induced effects of the JEDI estimates and those from Levitan &

Associates are $30.27 million and $33 million respectively. The JEDI model estimates a far higher output in indirect effects (“Turbine and Supply Chain Impacts”) than Levitan’s model does ($43.56 million vs $19 million).

Table 9. JEDI benefit model – current Block Island Wind project (National Renewable Energy Laboratory, 2015).

Under a scenario in which the RES minimum for wind energy is met with the

BIWF, the JEDI model is able to predict tangible changes in costs. As seen in Table 10,

O&M costs would increase to a total of 23% of annual operational expenses, versus the current status of 16% in the 30 MW wind farm. However, the JEDI model predicts a 38% decrease in CAPEX per kW from a 30 MW project to a 180 MW project.

32 Table 10. JEDI cost model – Energy 2035 plan scenario (180 MW).

If the BIWF were to fulfill the Energy 2035 target of 180 MW from offshore wind, the project would need to expand six-fold. When comparing the local economic impacts, the 180 MW scenario would increase the amount of full-time jobs during operating years by a factor of 5.59 (Table 11), nearly proportional growth. Total annual output would be five times larger than in the 30 MW case ($17.38 million vs. $2.90 million). This is a significant result, especially considering the finding above, in which

CAPEX drops but O&M increases. It would seem reasonable to state that the additional

33 O&M spending results in tangible economic benefits for the local economy in Rhode

Island.

Table 11. JEDI benefit model – Energy 2035 plan scenario (180 MW).

A JEDI cost model run for the 1st scenario (Table 12) of an increased BIWF output of 198 MW demonstrates a 39% reduction in CAPEX from the current 30 MW project, while O&M costs remain 23% higher, as seen in the 180 MW scenario as well.

Again, the JEDI model indicates that a slight reduction in CAPEX can be expected when project capacity is increased significantly.

34 Table 12. JEDI cost model – Scenario 1 (198 MW).

The 10% increase in project capacity from 180 MW to 198 MW results in near exact 10% increases for annual local economic impacts. The short-term impacts during the construction phase, observed in Table 13, are slightly less proportional, with increases of approximately 6-7% per item (compare figures in Tables 12 and 13).

35 Table 13. JEDI benefit model – Scenario 1 (198 MW).

The changes in CAPEX and O&M when the project is expanded to 216 MW

(Table 14) are the same as those between 180 MW and 198 MW.

Table 14. JEDI cost model – Scenario 2 (216 MW).

The second increased RES scenario of 216 MW (Table 15) returns 9% increases in annual job and output creation from the first scenario of 198 MW. Compared to the baseline Energy 2035 RES, the second scenario creates a proportional increase of 20% in job and overall economic value creation. The construction-period impacts improve approximately 6% from scenario 1 and 13-14% from the baseline 180 MW project.

37 Table 15. JEDI benefit model – Scenario 2 (216 MW).

The third scenario, a 30% increase to the baseline 180 MW expansion (Table 16), is where cost changes begin to curve away from those seen in the first two scenarios. The change in CAPEX per KWh from the 30 MW project is a 40% decrease, as opposed to the 39% decreases seen in the first two scenarios. Additionally, the CAPEX per KWh is

2% lower in scenario 234 MW scenario than in the 180 MW scenario. O&M remains

23% of total operational expenses. It stands to reason that within the JEDI model, continued increases in project size would have potential to yield even greater CAPEX savings.

38 Table 16. JEDI cost model – Scenario 3 (234 MW).

The third scenario returns short-term benefit increases of approximately 5% from the second scenario, and 19-20% from the baseline 180 MW scenario (Table 17). The gains in annual impacts are just above 8% for jobs and GDP growth from scenario 2 to 3.

However, the increases in long-term impacts in job creation and regional economic impact are directly proportional to the 30% increase in project size from the 180 MW scenario. The overall improvement in annual job creation is a factor of 7.3 from the current 30 MW project, and the annual local economic output is 7.2 times that of the 30

MW project. The trends from the current project, up to a 180 MW baseline, and through

39 the three scenarios demonstrate that the improvements in construction-period outputs can remain positive and consistent, and the improvements in annual job creation and overall economic impact are nearly, if not exactly, proportional to project capacity increases.

Table 17. JEDI benefit model – Scenario 3 (234 MW).

It can be seen from the LCOE figures in Table 18, that all expanded projects would result in a lower LCOE than the current BIWF project. Additionally, all fall below the average levelized costs of offshore wind in general as described by the EIA (EIA,

2017). As the project size expands, there are minor, but noticeable decreases in minimum and average LCOE, indicating that larger projects do have the potential to more efficiently leverage CAPEX and O&M. Through all calculations, the data generated by

40 the JEDI models provided the lowest estimates of LCOE, while those using the

Deepwater Wind data produced the highest estimates. This is likely explained by the fact that the JEDI model is more adaptive, using geographic and technology data to project a most likely scenario, whereas, in this thesis, the Deepwater Wind data was a simple extrapolation of value from the current project applied to projects of larger scale. Still, the higher LCOE values provided from the Deepwater Wind data offer a guiding upper- boundary of what is effectively the breakeven price of these projects.

Table 18. Levelized cost of energy comparison.

Despite the improvements in LCOE for an expanded BIWF, there is still a considerable cost increase associated with opting for offshore wind instead of natural gas.

Although subject to fluctuations in supply and price, natural gas remains the most cost-

41 effective option, in these cases. The minimum LCOE estimates for the expanded BIWF project, generated by the JEDI model, demonstrate competitiveness with only conventional combustion turbine natural gas plants. Furthermore, all combined-cycle natural gas plant maximum LCOE prices are still cheaper than the minimum estimates for each BIWF scenario not including an ITC. This finding is significant, as this demonstrates a viable option for a larger BIWF to accept a reduced PPA that drops prices for Rhode Island’s consumers but is not mutually inclusive with a negative NPV for

Deepwater Wind and their investors.

While still not as cheap as natural gas, the revised BIWF scenarios are slightly more competitive with natural gas in terms of LACE. In general, offshore wind tends to be slightly more competitive with natural gas during LACE measurements as a result of the higher overnight costs of fossil fuel plants. Overnight costs measure capital expenditures not incurred during construction periods, most offshore wind farms incur the majority of CAPEX during construction.

Despite the ability of offshore wind to compete on LACE prices, the current

BIWF is not competitive, with a LACE of $100.08 (Table 19), significantly higher than the EIA average LACE prices for offshore wind. Nevertheless, the expanded BIWF projects indeed offer an opportunity to generate more energy at a potentially lower

LACE, with minimum and average estimates falling significantly lower for the expanded scenarios than the current 30 MW BIWF. However, as the maximum column indicates, there is still some risk of a higher LACE, even with an ITC included.

42 Table 19. Levelized avoided cost of energy comparison.

Described in Table 20 are the results of the simple net value calculation, recommended by NREL. Using this definition of economic viability, none of the projects are worth pursuing, but all are an improvement on the current BIWF. NREL’s own estimates do not predict any offshore wind projects off the New England coastline with a positive net value until 2027 (Beiter, et al., 2016). Policy interventions that may reduce the LCOE such as production tax credits, investment tax credits, or feed-in tariffs are not incorporated.

43 Table 20. Net value results of expanded BIWF.

Deepwater Wind asserted during the Moore Testimony that the BIWF had potential to produce an internal rate of return (IRR) of 9.66%, and an NPV of $226, 729,

928.95 was calculated during this thesis (State of Rhode Island Public Utilities

Commission, 2010). It is important to note that the IRR of the current BIWF is not known beyond an initial projection. During this thesis research, IRR calculations run for the 30

MW BIWF returned a value of 5.69%, in contrast to Deepwater Wind’s own calculations, which may have included different factors.

Using the 5.69% value calculated during this thesis, it is clear from Table 21 below that achieving a comparable level of IRR is achievable in most scenarios when using the data from the Deepwater Wind extrapolations and the JEDI model.

Additionally, the three expanded scenarios beyond the Energy 2035 proposal offer improved IRR using all three data sources. The middle range IRR projections without an

ITC are just below the values stated in the Deloitte analysis, while those with an ITC fall into the expected range, and the higher estimates are more than double Deloitte’s

44 predictions (Deloitte, 2014). It is also worth noting that the IRR stays positive in all scenarios.

Table 21. Internal rate of return comparison for expanded BIWF.

NPV calculations with an assumed discount rate of 7% were run for all scenarios, including the baseline 30 MW BIWF. The NPV results in Table 22 below indicate that controlling CAPEX at the project outset will likely be the most crucial step in offering a profitable investment thesis to investors. While all maximum NPV scenarios offer the possibility to exceed the predicted NPV of the BIWF, the risk of negative NPV remains and as such could deter investment interest.

45 Table 22. Net present value of expanded BIWF.

Although all scenarios become more optimistic with the inclusion of an ITC, the most likely ways in which the expanded BIWF projects could provide better NPV would include fundamental changes in the technology or an increase in price by electricity providers.

Although the electricity prices for consumers of electricity from BIWF are pre- determined by a PPA, it is important to acknowledge the minimum (breakeven) prices in order to assess the levels at which a project can still profit. In Table 23 below, a range of breakeven prices for consumers are listed for each expanded scenario, in comparison with the current price per KWh for consumers and the prices that will be incurred by consumers during the tenure of the current BIWF.

It is clear from the chart above that the expanded scenarios can indeed deliver energy to consumers at prices cheaper than that of the current BIWF. However, the price escalations included in the current BIWF are critical to maintaining profitability and a positive NPV. More research is required to understand levels of price escalation that would be necessary to maintain an attractive investment thesis for the expanded scenarios.

46 When observing the gaps between breakeven for the hypothetical project scenarios and the current rates for Rhode Islanders, it is clear that larger offshore wind projects can profit without significantly raising rates for Rhode Islanders. If a mandatory minimum RES were in place, it would indeed be possible for the Rhode Island state government to create a market for offshore wind.

Table 23. Consumer price comparison.

A distinct advantage of offshore wind versus natural gas is that opting for offshore wind would displace carbon emissions generated by natural gas electricity generation. Table 24 below lists and estimates the amount of emissions from electricity consumed in Rhode Island at different intervals, and includes an estimate of the amount of emissions that could be displaced annually by implementation of offshore wind projects at the MWh totals explored in this thesis. It is clear from the figures below that there would be tangible and considerable reductions in annual emissions by opting for large-scale renewable energy, even when compared to the current reductions that the state enjoys as a result of the BIWF coming into operation.

47 Table 24. Emissions comparison.

While considerable emissions would be displaced by the implementation of more renewable energy in Rhode Island, it is still important to quantify the cost of displacing these emissions so that the implementation of offshore wind may be compared with other methods of carbon emission reduction. It can be seen from Table 25 below that expanded projects (and by association, increased emissions reduction) do not directly translate into an observable trend of mitigation cost reduction. From a purely economic standpoint, it may be more logical to instead invest in energy efficiency measures or carbon sequestration at point of emission.

Table 25. Cost of mitigation comparison.

Chapter IV

Discussion

The results from the calculations listed in the previous section offer insight on how the initial research questions can be answered. The variation in results provides an important comment on the unknowable risks still associated with offshore wind investment.

Conclusions

An initial research question was whether or not the Block Island Wind Farm could be expanded from 30 MW to 180 MW (in order to meet the Energy 2035 proposed

RES for offshore wind) and still remain attractive to investors and the regional economy.

The follow-on question was whether changes to the RES could influence the profitability and economic outcomes of the project.

It can be seen from the calculations in Tables 21 and 22 that there are indeed differing results in profitability based on project size, but often more variation in outcomes based on the more detailed project cost assumptions, i.e., the CAPEX and

O&M per KWh or MWh generated. A metric suggested at the beginning of the thesis was to quantify the possibility of the project becoming at least 20% more profitable in scenarios of expansion. The data in Table 22 suggests that while this is possible, it should not be considered likely with the status quo technology, for all NPV calculations run with data from the EIA or current BIWF, the NPV was negative. The JEDI models consistently predicted significantly lower CAPEX for each scenario than did the EIA or

4 9 Deepwater Wind data (see Appendix for detailed cash flows), even though the JEDI models did not always predict the lowest O&M costs. It is worth noting that the JEDI models place significance on the size, nameplate capacity, and distance from shore of turbines, allowing for a more granular analysis of how technical details affect CAPEX. In contrast, the data from EIA estimates are averages from similar sized total projects and the data from the current BIWF is an extrapolation of values from a singular instance, without the same flexibility that the JEDI models have with regard to projecting technological advantages onto projects of varying scale.

The results from the electricity price comparisons demonstrate that it will be possible to maintain or closely match status quo electricity prices in Rhode Island with electricity generated from offshore wind. The deeper question is to what level profit margin thinning could be tolerated in order to still gain investment. Indeed, as a private sector project meeting a government target, there is the possibility to remain somewhat immune from competition, but unless government funds are to be directly injected into the project, it is still critical to offer profit potential in order to avoid a stalled investment process. There is more promise for a drop in breakeven price when the ITC is incorporated, allowing for a better cushion when attempting to maintain low prices but preserve profits. Rhode Island is currently debating a carbon tax of $15 per metric ton of

CO2 generated. While this would not directly influence the price and profits of offshore wind, it would raise the breakeven price of natural gas, opening up the market to more competition from offshore wind.

It is clear from calculations in the JEDI models that tangible economic benefits can be reaped from an expanded Block Island Wind Farm project. It is important to

50 remember that the JEDI models are run with specific regional and technological values incorporated in calculations, thus resulting in less general estimates. The growth of the project brings more long-term jobs and improved economic output under the JEDI model.

A good follow-up to this research would be to stretch the parameters even further, looking at projects that generate up to 500 or 600 MW, and observing the trend in economic development outputs. More real-world data from offshore wind projects in the

United States will be necessary to make sound assessments of NPV predictions. The

JEDI models incorporate dozens of variables into calculations, but will need stronger data points from completed projects to carry more weight.

The case for investors depends heavily on the CAPEX and O&M values. As can be seen in the LCOE and LACE results, the true cost of offshore wind projects, while improving, remains high when compared with that of natural gas. A carbon tax or other punitive measure levied against carbon-emitting plants would improve the competitiveness of offshore wind LCOE in Rhode Island. In other regions that rely on more capital-intensive incumbent energy systems, offshore wind may be practical, but in

Rhode Island, where the major competitor is natural gas, the LCOE and LACE will need to improve. This points to the importance of technological development as the best means by which project costs can be improved. For example, technologies that are cheaper to produce, or offer improved capacity factors would have the potential to drastically improve the business case for offshore wind. It can be argued from the LCOE and LACE results that a more prudent investor may want to first consider the rate of hardware development in this space and compare the options of executing the project now or delaying until more cost-saving technologies become available.

51 Inclusion of an investment tax credit (ITC) creates significant cost relief for projects of every size. The LCOEs of each scenario (Table 18) dropped by levels of 7-

17% when an ITC was included.

These results indicate that in order to be considered a legitimate cost-competitor with natural gas, the proposed offshore wind projects would indeed still require some type of market intervention through tax incentives or subsidies. Nonetheless, the LCOE values calculated in Table 18 match or outpace expectations listed by NREL’s estimated

LCOE values by region (Table 26). If compared to the NREL estimates, the LCOE values generated in this thesis would be higher than expected for commercial operation dates

(COD) in 2015 and 2022, and competitive with expectations for projects commencing operations in 2027.

Table 26. NREL estimated LCOE ranges by U.S. regions (Beiter, et al., 2016).

Similar to the LCOE and LACE results, the mixed IRR and NPV results point to a level of uncertainty that investors will face in this space as long as there is no direct

52 government involvement in the project. Indeed, the business case improves significantly when the ITC is incorporated, and the emergence of carbon taxes would put pressure on grids to diversify energy procurement. The IRR and NPV of the projects outlined in this thesis could be greatly improved by higher prices in PPAs with grid companies. This, however, would likely be subject to government review, and would need to demonstrate utility beyond just those that benefit investors.

Recommendations

It is clear from the calculations in this thesis that, while O&M does vary, CAPEX reductions are critical to improving profitability. Reductions in LCOE are indeed occurring, a recent case of a 350 MW wind farm in Denmark provides reason for optimism, returning a $67/MWh LCOE (Wiser, et al., 2016). Recent papers have predicted continued decreases in CAPEX, O&M, and LCOE as turbine sizes increase (see

Figure 6 below). Innovations in offshore wind hardware are the best opportunity to produce more energy with less equipment and labor.

Figure 6. Impact of turbine size on project cost (Valpy, Freeman, & Roberts, 2016).

In order to achieve the level of technical development necessary to drive CAPEX costs down, better R&D will be necessary. Investing in R&D will be an unavoidable step if the underlying technology for offshore wind is to be improved. Government R&D grants could play a pivotal role in reducing offshore wind CAPEX and in turn bringing costs down for consumers. As seen in Figure 5 earlier, R&D grants make up a small portion of European interventions in offshore wind, if the U.S. were to adopt a comparable or even more ambitious system of R&D grants, there would be higher likelihood of companies being able to develop technology that can drive profitable free- market projects.

Additionally, it will not be immediately possible to transition offshore wind energy into the mainstream without strong PPAs. While this thesis initially proposed that higher mandatory minimum procurement standards could create markets for offshore wind, the author would now adjust this hypothesis to explore to what level PPAs can

54 create markets. Indeed, the stability of profits necessary to operate and the avoidance of price shocks by consumers are better addressed by PPAs than mandatory minimums.

Research Limitations

Research limitations were encountered in the form of data access. Deepwater

Wind was contacted during the research phase, but chose not to comment on the costs or predicted cash flows from this project or any proposed expansions out of confidentiality concerns. As a result, approximations based on cost extrapolations, industry averages, and the values generated by the JEDI models were used to demonstrate alternating potential outcomes. Furthermore, the majority of offshore wind projects in the EU receive generous subsidies or tax incentives, in addition to more ambitious PPAs, as a result it is only possible to make limited predictions for how offshore wind will perform in a predominately free-market system. Given that the BIWF is the first operational offshore wind farm in the United States, and only began operation in 2016, there is an obvious risk associated with taking the project’s projections at face value.

While this thesis attempted to take into account all significant factors in natural gas prices in Rhode Island, it may not be feasible to accurately predict circumstances in exporter states. Furthermore, prices of both natural gas and offshore wind energy are subject to application and repeal of subsidies throughout the next 20 years. In the specific cases calculated here, it was useful to look at project costs and profits with and without an ITC, which could be modified at some point. Although plans are in initial discussion, there is no established path toward the implementation of a carbon tax or any subsidies for renewable energy beyond the RES. Factors such as future disagreements or consensus on government measures to improve the case for renewables are difficult to quantify.

55 The efficiency of offshore wind power is largely attributed to the ability of current technology and management schemes to produce cost-effective offshore wind scenarios.

Any technological change in turbines, maintenance equipment, or innovations in management techniques is certain to change the efficiency of operations and likely to improve profitability. While we can observe trends in technology and its effect on energy prices, it is difficult to predict how private sector technologies will evolve within the market and whether government-subsidized research and development will accelerate in the coming years.

56 Appendix

Project Cash Flow Analyses

Table 27. BIWF cash flow (State of Rhode Island Public Utilities Commission, 2010).

60 Table 28. Energy 2035 baseline (180 MW) cash flow with Deepwater Wind data.

62 Table 29. Energy 2035 baseline (180 MW) cash flow with JEDI model data.

64 Table 30. Energy 2035 baseline (180 MW) cash flow with EIA data.

66 Table 31. Scenario 1 (198 MW) cash flow with Deepwater Wind data.

68 Table 32. Scenario 1 (198 MW) cash flow with JEDI data.

70 Table 33. Scenario 1 (198 MW) cash flow with EIA data.

72 Table 34. Scenario 2 (216 MW) cash flow with Deepwater Wind data.

74 Table 35. Scenario 2 (216 MW) cash flow with JEDI data.

76 Table 36. Scenario 2 (216 MW) cash flow with EIA data.

78 Table 37. Scenario 3 (234 MW) cash flow with Deepwater Wind data.

80 Table 38. Scenario 3 (234 MW) cash flow with JEDI model data.

82 Table 39. Scenario 3 (234 MW) cash flow with EIA data.

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