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OCS Study

MMS 2007-050

**Fiscal Cost-Benefit Analysis to Support the Rulemaking Process for 30
CFR 285 Governing Alternative Energy Production and Alternate Uses of
Existing Facilities on the Outer Continental Shelf**

**Final Technical Report**

![](media/image2.wmf)

> OCS Study

MMS 2007-050

**Fiscal Cost-Benefit Analysis to Support the Rulemaking Process for 30
CFR 285 Governing Alternative Energy Production and Alternate Uses of
Existing Facilities on the Outer Continental Shelf**

**Final Technical Report**

Authors

John C. Weiss, Brent B. Boehlert, and Jennifer R. Baxter

February 2008

Prepared under MMS Contract

GS10F0061N

by

Industrial Economics, Incorporated

2067 Massachusetts Avenue

Cambridge, Massachusetts 02140

Published by

**DISCLAIMER**

This report was prepared under contract between the Minerals Management
Service (MMS) and Industrial Economics, Incorporated (IEc). This report
has been technically reviewed by the MMS, and it has been approved for
publication. Approval does not signify that the contents necessarily
reflect the views and policies of the MMS, nor does mention of trade
names or commercial products constitute endorsement or recommendation
for use. It is, however, exempt from review and compliance with the MMS
editorial standards.

**CITATION**

Suggested citation:

Weiss, J.C., B.B. Boehlert, and J.R. Baxter.  2008.  Fiscal Cost-Benefit
Analysis to Support the Rulemaking Process for 30 CFR 285 Governing
Alternative Energy Production and Alternate Uses of Existing Facilities
on the Outer Continental Shelf.  OCS Study MMS 2007-050. Herndon, VA: 
USDOI/MMS, Offshore Environmental Division. 101 pp.

**ACKNOWLEDGMENTS**

The authors would like to thank Roger Bedard (Electric Power Research
Institute) and Walt Musial (National Renewable Energy Laboratory) for
their technical contributions to this report.

**TABLE OF CONTENTS**

PAGE

[LIST OF TABLES iv](#list-of-tables)

[LIST OF FIGURES vii](#list-of-figures)

[EXECUTIVE SUMMARY viii](#executive-summary)

[1.0 INTRODUCTION 1](#introduction)

[1.1 Need for a regulatory impact analysis
1](#need-for-a-regulatory-impact-analysis)

[1.2 Scope of the analysis 3](#scope-of-the-analysis)

[1.3 Description of the baseline and alternative
3](#description-of-the-baseline-and-alternative)

[1.4 Report outline 4](#report-outline)

[2.0 FORECAST OF ALTERNATIVE ENERGY DEVELOPMENT ON THE OUTER CONTINENTAL
SHELF
6](#forecast-of-alternative-energy-development-on-the-outer-continental-shelf)

[2.1 Renewable energy resources on the OCS
7](#renewable-energy-resources-on-the-ocs)

[2.1.1 Wind 7](#wind)

[2.1.2 Wave 9](#wave)

[2.1.3 Ocean current 10](#ocean-current)

[2.2 Renewable energy generation technologies
10](#renewable-energy-generation-technologies)

[2.2.1 Wind 10](#wind-1)

[2.2.2 Wave 11](#wave-1)

[2.2.3 Ocean current 13](#ocean-current-1)

[2.3 Renewable energy technology cost trends
13](#renewable-energy-technology-cost-trends)

[2.3.1 Wind 13](#wind-2)

[2.3.2 Wave 15](#wave-2)

[2.3.3 Ocean current 16](#ocean-current-2)

[2.4 Renewable energy economics 16](#renewable-energy-economics)

[2.5 Renewable energy capacity expansion
17](#renewable-energy-capacity-expansion)

[2.6 Integration of OCS electricity generation into transmission
networks
18](#integration-of-ocs-electricity-generation-into-transmission-networks)

[2.7 Conclusions 19](#conclusions)

[3.0 ESTIMATION OF FEDERAL GOVERNMENT COSTS IN THE BASELINE AND
ALTERNATIVE
25](#estimation-of-federal-government-costs-in-the-baseline-and-alternative)

[3.1 General approach 25](#general-approach)

[3.2 Discussion 28](#discussion)

[4.0 ESTIMATION OF TRANSFER PAYMENTS TO THE U.S. TREASURY RESULTING FROM
PROJECTS INCLUDED IN THE ALTERNATIVE ENERGY DEVELOPMENT FORECAST
30](#estimation-of-transfer-payments-to-the-u.s.-treasury-resulting-from-projects-included-in-the-alternative-energy-development-forecast)

[5.0 SENSITIVITY OF ANALYSIS TO KEY ASSUMPTIONS
42](#sensitivity-of-analysis-to-key-assumptions)

[5.1 Electricity Price Sensitivity Analysis
42](#electricity-price-sensitivity-analysis)

[5.2 Sensitivity of Model Results to Inclusion of REC Payments
43](#sensitivity-of-model-results-to-inclusion-of-rec-payments)

[5.3 Multivariate Analysis 45](#multivariate-analysis)

[6.0 IMPACT OF PRODUCTION TAX CREDIT ON PROJECT VIABILITY
52](#impact-of-production-tax-credit-on-project-viability)

[7.0 NET REVENUES ANALYSIS 56](#net-revenues-analysis)

[8.0 QUALITATIVE ANALYSIS OF COSTS AND REVENUES ASSOCIATED WITH
ALTERNATE USES OF EXISTING OCS FACILITIES
64](#qualitative-analysis-of-costs-and-revenues-associated-with-alternate-uses-of-existing-ocs-facilities)

[8.1 Alternate Uses of Existing Facilities
64](#alternate-uses-of-existing-facilities)

[8.1.1 Aquaculture 64](#aquaculture)

[8.1.2 Oil and gas support functions 64](#oil-and-gas-support-functions)

[8.1.3 Education and research 65](#education-and-research)

[8.1.4 Desalination 65](#desalination)

[8.1.5 Telecommunications 65](#telecommunications)

[8.1.6 Medical care 65](#medical-care)

[8.1.7 Leisure and recreation 65](#leisure-and-recreation)

[8.2 Potential Federal revenues 65](#potential-federal-revenues)

[8.3 Potential Federal costs 66](#potential-federal-costs)

[8.4 Qualitative assessment of net fiscal impact
66](#qualitative-assessment-of-net-fiscal-impact)

[9.0 Distribution of fiscal impacts 67](#distribution-of-fiscal-impacts)

[9.1 Number of small entities to which the rule will apply
67](#number-of-small-entities-to-which-the-rule-will-apply)

[9.2 Economic impact of the rule on affected small entities
68](#economic-impact-of-the-rule-on-affected-small-entities)

[9.3 Initial Regulatory Flexibility Analysis
69](#initial-regulatory-flexibility-analysis)

[LITERATURE CITED 72](#literature-cited)

APPENDIX A - MODEL DESCRIPTION

APPENDIX B - PROJECT FINANCIAL INFORMATION

# LIST OF TABLES

[TABLE]{.underline} [PAGE]{.underline}

2-1 Estimate of U.S. Offshore Wind Energy Resources (Megawatts) by
Region and Water Depth 8

2-2 DOE Estimate of U.S. Offshore Wind Energy Resources by NERC Region 8

2-3 Assumed Capital Costs (per kW) for U.S. Offshore Wind Energy
(2007\$) 15

2-4 Assumed Capital Costs for U.S. Offshore Wave Energy (2007\$) 16

2-5 EPRI \"Optimistic\" Forecast of U.S. Wave Energy Capacity
Development 18

2-6 Preliminary OCS Development Forecast, 2008-2036 22

2-7 Preliminary OCS Development Forecast by Project Type and Region,
2008-2036 24

3-1 MMS Per-Project Cost Template, 2008-2012 (Fractions of Full-Time
Equivalent) 26

3-2 MMS Per-Project Cost Template, 2013-2027 (Fractions of Full-Time
Equivalent) 27

4-1 Results of Economic Viability Screening for Projects Operational by
2027 34

4-2 Results of Economic Viability Screening for Wind Projects
Operational by 2027

34

4-3 Results of Economic Viability Screening for Wave Projects
Operational by 2027

35

4-4 Results of Economic Viability Screening for Current Projects
Operational by 2027

35

4-5 Installed Capacity of Constructed Wind, Wave, and Current Projects
Operational by 2027 36

4-6 Description of Key Cash Flow Model Inputs 37

4-7 Low, Intermediate, and High Payment Cases 40

5-1 Effect of Electricity Price on Net Federal Revenues and Project
Financial Feasibility 43

**LIST OF TABLES (cont.)**

[TABLE]{.underline} [PAGE]{.underline}

5-2 Modeled REC Payments by Region 44

5-3 Results of Economic Viability Screening for Projects Operational by
2027 44

5-4 Net Federal Revenues 2008 to 2027 (Undiscounted) for the
Intermediate-No REC Scenario 45

5-5 Points Defining the Triangle Distribution of Uncertain Variables 48

6-1 Results of Economic Viability Screening for Projects Operational by
2027, No-PTC Scenario 52

6-2 Results of Economic Viability Screening for Wind Projects
Operational by 2027, No-PTC Scenario 53

6-3 Results of Economic Viability Screening for Wave Projects
Operational by 2027, No-PTC Scenario 54

6-4 Results of Economic Viability Screening for Current Projects
Operational by 2027, No-PTC Scenario 54

6-5 Installed Capacity of Constructed Wind, Wave, and Current Projects
Operational by 2027, No-PTC Scenario 55

7-1 Present Value of Cumulative Net Revenues (Millions) in Constant 2008
\$, All Projects, 2008-2027 58

7-2 Annual Revenues and Costs (Millions) in Undiscounted Nominal \$, All
Projects, Baseline Case 58

7-3 Annual Revenues and Costs (Millions) in Undiscounted Nominal \$, All
Projects, Low Payment Case 59

7-4 Annual Revenues and Costs (Millions) in Undiscounted Nominal \$, All
Projects, Intermediate Payment Case 60

7-5 Annual Revenues and Costs (Millions) in Undiscounted Nominal \$, All
Projects, High Payment Case 61

7-6 Present Value of Cumulative Net Revenues (Millions) in Constant 2008
\$, Wind Projects, 2008-2027 62

7-7 Present Value of Cumulative Net Revenues (Millions) in Constant 2008
\$, Wave Projects, 2008-2027 62

**LIST OF TABLES (cont.)**

[TABLE]{.underline} [PAGE]{.underline}

7-8 Present Value of Cumulative Net Revenues (Millions) in Constant 2008
\$, Ocean Current Projects, 2008-2027 62

7-9 Present Value of Cumulative Net Revenues (Millions) in Constant 2008
\$, Atlantic Region Projects, 2008-2027 63

7-10 Present Value of Cumulative Net Revenues (Millions) in Constant
2008 \$, Gulf Region Projects, 2008-2027 63

7-11 Present Value of Cumulative Net Revenues (Millions) in Constant
2008 \$, Pacific Region Projects, 2008-2027 63

9-1 Significance of Compliance Costs 69

A-1 Descriptions of Tables in the General Inputs, Project Inputs, and
Financial Assurance Worksheets A-3

B-1 Forecasted Electricity Production and Financial Performance
Information for Projects Operational by 2027 B-1

# LIST OF FIGURES

[FIGURE]{.underline} [PAGE]{.underline}

5-1 Example of a Triangle Distribution 47

5-2 Probability Distribution of Net Federal Revenues (2008 to 2027)
Given Variation of Assumptions, Discounted at 3 Percent, Variation in
Price Included 49

5-3 Sensitivity of Net Federal Revenues (Discounted at 3 Percent) to
Model Assumptions, Variation in Price Included 50

5-4 Probability Distribution of Net Federal Revenues (2008 to 2027)
Given Variation of Assumptions, Discounted at 3 Percent, No Variation in
Price 51

5-5 Sensitivity of Net Federal Revenues (Discounted at 3 Percent) to
Model Assumptions, Variation in Price Not Included 51

A-1 Structure of Excel-Based Cash Flow Model A-2

# executive summary

The Energy Policy Act of 2005 *(*EPAct), specifically section 388,
amended the Outer Continental Shelf (OCS) Lands Act to authorize the
Secretary of the Interior to (1) issue leases, easements, or
rights-of-way on the OCS for producing or supporting the production of
energy resources other than oil and gas, and (2) to authorize other
energy and marine-related activities that involve the use of existing
facilities on the OCS. The EPAct also required the Department of the
Interior to develop any necessary regulations to implement this new
authority and to implement alternative energy revenue sharing
requirements.[^1] On March 20, 2006, the Secretary officially delegated
this new authority, and responsibility for developing any necessary
regulations, to the Minerals Management Service (MMS). The implementing
regulations and the revenue sharing regulations have been assigned
Regulation Identifier Number 1010-AD30 (\"AD30\").

The importance of these regulations stems from the growing interest in
harnessing the energy production potential that is available on the OCS
and the current lack of a formal system to facilitate such activity.
Prior to the EPAct, the Federal government did not have clear authority
to seek payment for private interests\' access to and use of Federal
submerged lands, nor authority to establish a comprehensive program for
regulating all aspects of alternative energy development on the OCS,
including siting, construction, operation, and decommissioning. These
regulations will serve an important social purpose by establishing a
payment structure to ensure a fair return to the United States for any
lease, easement, or right-of-way granted; by creating a comprehensive
"cradle-to-grave" regulatory program with provisions for regular
inspections and environmental monitoring; and by providing a degree of
regulatory certainty to those proposing, planning, or potentially
financing an offshore alternative energy project.

MMS is required to conduct economic analyses of proposed regulations if
they are determined to be significant, as that term is defined in
Executive Order 12866. Regulation AD30 is considered significant
because, by establishing a new regulatory program, it would raise novel
legal or policy issues. If actual development of OCS alternative energy
projects were consistent with the scenario presented in this analysis,
net Federal revenues may exceed \$100 million in some years, but
payments to Federal agencies represent a transfer of money from one set
of entities to another, not the actual effect on the economy.

Discussions between MMS and OMB resulted in a determination that the
appropriate analysis of the proposed regulation is one that focuses on
its fiscal impacts. While fiscal revenues (i.e., the revenues the
Federal government will receive due to economic activity that occurs
under the regulation) are traditionally considered a transfer
payment,[^2] in this analysis they are treated as a benefit. The cost
side of the analysis comprises the Federal government\'s costs to
implement the program that will administer the proposed regulation. In
addition, as required by the Regulatory Flexibility Act (RFA) of 1980
(as amended by the Small Business Regulatory Enforcement Fairness Act of
1996 (SBRFA) and Executive Order 13272 ("Proper Consideration of Small
Entities in Agency Rulemaking")), this analysis considers whether the
fiscal payments made by the developers of regulated projects to MMS will
significantly affect a substantial number of small entities.

**[Regulatory alternative]{.underline}**

For the purposes of this analysis, the baseline condition is a
continuation of the regulatory regime that existed prior to passage of
the EPAct, under which other Federal agencies, such as the Army Corps of
Engineers (in the case of wind energy) and the Federal Energy Regulatory
Commission (FERC, in the case of wave and ocean current energy), assumed
primary responsibility for reviewing and permitting alternative energy
projects on the OCS. The regulatory alternative to the baseline, as
described in this rulemaking, is the MMS program authorized by Section
388 of the EPAct, comprising the granting of property rights, collection
of payments for alternative energy and other uses of the OCS (in the
form of lease rentals and operating fees), and establishment of a
comprehensive "cradle-to-grave" regulatory program for authorizing
alternative energy activity on the OCS. The analysis further considers
three different sets of fiscal terms (identified as the \"Low,\"
\"Intermediate,\" and \"High\" payment cases), which vary in the way
fees and rental payments are calculated. These payment cases are
explained in Section 4 of the report. The main analysis uses the same
assumptions regarding electricity prices and other such phenomena for
each case. Other scenarios, based on the same payment cases, are
presented in Appendix B and Appendix D. The analysis considers projects
that are constructed and that begin operations (i.e., begin to generate
electricity for sale) or that are in development during the 20-year
period from 2008-2027. While these projects would have revenue and cost
impacts that extend beyond this period (based on 20 years of electricity
generation over an assumed 25-year operational term), the only fiscal
impacts reported are those that occur during the period 2008-2027.

**[Analytic methodology]{.underline}**

The process of estimating the revenues and costs associated with 20
years of future project development (and subsequent operations that
occur during that 20-year period) requires a number of key assumptions
regarding individual project characteristics, project financing, and
electric power market conditions. Our specific methodology for
calculating net revenues comprised three general steps: the development
of a forecast of OCS project activity during the period 2008-2027; the
creation of an Excel-based spreadsheet model that tracks annual cash
flow for each project in the forecast and permits a calculation of each
project\'s annual payments to the Federal government (in the form of
rentals and fees); and the assessment of the costs the Federal
government is expected to incur to administer the program created by
this rule (principally the review of project development plans). Net
revenues, on an annual or a cumulative basis, are the difference between
estimated Federal revenues and estimated Federal costs.

Creation of a forecast of OCS alternative energy project activity is
subject to considerable uncertainty, as these will be the first projects
of their kind in United States waters and will be entering a market that
is, and will continue to be, evolving. For the purposes of this
rulemaking, a forecast is constructed on a foundation of existing
project proposals, with growth from that base predicated on the general
presumption that regulatory, technical, and financial conditions during
the period of analysis will support rather than constrain development
activity. The forecast includes wind, wave, and ocean current energy
projects in three geographic regions (Atlantic, Gulf of Mexico, and
Pacific). Refinement of an initial forecast was based on a review of
readily available literature and other sources of information that
address estimates of renewable energy resources on the OCS; descriptions
of existing and planned renewable energy generation technologies that
might be used to exploit OCS resources; estimates of potential cost
trends over time for different renewable energy technologies; estimates
of when different technologies are expected to be \"economically
deployable\"; estimates of OCS renewable energy generating capacity
expansion on an annual or semi-annual basis; and discussions about the
integration of OCS electricity generation into the onshore transmission
grid. The resultant preliminary forecast includes 76 projects that begin
generating electricity prior to 2028.

Annual costs are based on MMS forecasts of the personnel that will be
required for program activities and per-project level of effort
estimates for each position in the personnel mix at each stage of a
project\'s lifecycle. The level of effort estimates are expressed as
fractions of annual full time equivalents (FTEs). The project lifecycle
stages are divided into one-year increments. Costs are assigned to each
position based on an assumed pay grade, specified by MMS, with a fixed
indirect cost rate applied to base compensation for each grade. MMS also
specified an annual cost of living adjustment (three percent) to use in
determining future year costs. In addition, MMS estimated additional
program-related costs that cannot be assigned to individual projects but
that are directly related to implementation of the regulations (e.g.,
preparatory work for an anticipated lease sale).

The cash flow model used to estimate payments to the Federal government
incorporates both project-specific and general assumptions. The
project-specific assumptions include technical details (e.g., size,
capacity factor, capital and operations and maintenance costs, years to
construct) as well as the initial value of financial incentives (i.e.,
the Production Tax Credit (PTC) and renewable energy certificates
(RECs), as appropriate) for each of the projects in the development
forecast. General assumptions address factors such as regional
electricity price forecasts and construction financing terms. In
addition, the model incorporates assumptions consistent with the
financial assurance requirements as specified in the rule. For each
project in the preliminary development forecast, the cash flow statement
covers the entire project lifetime, from pre-development through
operations to decommissioning. Thus, the last project in the forecast
begins operation in 2027 and operates through 2046. However, as
described above, for the purposes of this analysis we only report the
Federal revenues and costs that are realized during the period
2008-2027.

In general, assumptions incorporated into the model reflect the
electricity and alternative energy markets and policy landscapes as they
existed at the time of the analysis. With one exception, we did not
assume any market or policy changes that might provide an advantage or
disadvantage to OCS alternative energy projects during the period of
analysis. Furthermore, we assumed that any factor in place at the time
of the analysis would remain in place throughout the period of analysis.
The exception to this rule was an assumption that the Federal PTC would
become available to wave and ocean current energy projects prior to the
operational phases of the first projects of these kinds.

As part of our examination of the cash flow for each project in the
development forecast (given model assumptions), we established specific,
internal rate of return (IRR)-based criteria for the evaluation of
economic viability. Below a certain IRR, we assumed that the project
might be proposed but would not formally enter the pre-development
phase, and thus would not result in any Federal revenues or costs. For
projects that exhibited an IRR above a minimum value but below a target
value, we assumed that some pre-development activity would occur but
that construction and operation of the project would not. In these
cases, we calculated and recorded Federal revenues and costs associated
only with the predevelopment period. We calculated and recorded all
Federal revenues and costs for the projects with an IRR above the target
value. The effect of this viability analysis was a reduction (from the
original universe of 76) in the number of projects included in the net
revenue calculation for the Low, Intermediate, and High payment cases.

We analyzed the sensitivity of our results to key assumptions.
Variations in electricity price had the greatest influence on evaluation
results, followed by variations in capacity factor. We also analyzed the
impact of the REC and PTC financial incentives on project viability.
Total viable projects might be reduced by 25 percent without revenue
from REC sales. Thus, renewable portfolio standards implemented by
coastal states could be essential to the economic success of many OCS
projects. A reduction in total viable projects of more than 40 percent
may occur if the PTC is not available, suggesting that this incentive is
the most significant one for investors.

**[Results]{.underline}**

As of January 1, 2008, at a three percent discount rate, the present
value of cumulative net Federal revenues over the 20-year period of the
analysis ranges from approximately -\$9.3 million and -\$57.3 million in
the Baseline and Low cases, respectively, to approximately \$357 million
and \$538 million in the Intermediate and High payment cases,
respectively. With a 7 percent discount rate, the present value of
cumulative net Federal revenues over the period of the analysis ranges
from approximately -\$7.8 million and -\$46.5 million in the Baseline
and Low cases, respectively, to approximately \$190 million and \$291
million in the Intermediate and High payment cases, respectively. The
significant difference in net revenues is attributable to the inclusion
of operating fee payments to MMS in the latter two cases.[^3] These
operating fees are relatively large in comparison to the other fees paid
to MMS in all three cases. Categorization of the results by technology
and region highlights the impact of wind energy projects and the
Atlantic region, which, respectively, account for over 99 percent and
approximately 79 percent of the present value cumulative net revenues in
the Intermediate payment case.

**[Regulatory Flexibility Act analysis]{.underline}**

Under the requirements of the RFA, as amended by SBRFA and Executive
Order 13272, Federal agencies must consider the potential distributional
impact of new rules on small businesses, small governmental
jurisdictions, and small organizations. MMS is required to prepare a
regulatory flexibility analysis and take other steps to assist small
entities, unless it certifies that the rule will not have a "significant
economic impact on a substantial number of small entities."
Certification of the rule must include a statement providing the factual
basis for this determination. The remainder of this section summarizes
the results of MMS's screening analysis used to determine whether it can
certify the rule.

Given the immaturity of the offshore alternative energy industry, it is
difficult to develop an accurate count of the number and size of
entities that will or may be subject to this rule in order to determine
whether the rule will affect a \"substantial\" number of small entities.
The most appropriate North American Industry Classification System
(NAICS) code for the industry affected by the proposed rule is 221119
(Other Electric Power Generation).[^4] An entity within this
classification is "small" if it is \"primarily engaged in the
generation, transmission, and/or distribution of electric energy for
sale and its total electric output for the preceding fiscal year did not
exceed four million megawatt hours" (MWh). We assume that many of the
entities subject to the rule will likely exist, during the period of
analysis, solely to develop one or more offshore alternative energy
projects that combined will not have a total electric output greater
than 4 million MWh (corresponding to an offshore wind project with a
rated capacity of more than 1,100 MW, which is larger than the largest
project included in our 20-year forecast). Some entities, either through
a combination of projects or through the incorporation of offshore
alternative energy projects into a larger portfolio of electricity
generating stations, will exceed the four million MWh threshold.

Several companies have formally or informally expressed interest in
being granted access to the OCS for electricity generation purposes. At
least 40 to 50 entities are identifiable as potential project or
technology developers with a focus on utilizing offshore wind, wave, or
ocean current resources. The U.S. Census Bureau\'s 2002 Economic Census
reported 411 entities within NAICS code 221119. However, for the
purposes of this analysis we assume that most of the relevant entities
will be considered \"small,\" and therefore can conclude that a
substantial number of small entities will be affected.

The significance of the impact on small entities is assessed in this
case by comparing the compliance costs (i.e., the payments to the
Federal government) required under the rule to the total revenues
generated by the subject entities. For this analysis, we consider all
project revenues and payments to the Federal government associated with
the projects that meet the target IRR value, regardless of when they
occur (i.e., the analysis considers revenues and payments that occur
post-2027). For each payment case, we calculate the ratio of annualized
per project payments to annualized per project revenues over the
lifetime of each project. This ratio provides a conservative estimate of
the impact of compliance costs on small entities because it assumes that
(1) all of the affected projects are undertaken by small entities, (2)
each entity undertakes a single project, and (3) all revenues for each
entity are derived solely from this renewable energy project (i.e., the
companies involved do not have groups of projects or other business
interests). Therefore, the results of this screening analysis are more
likely to overstate than understate the significance of compliance costs
to affected entities.

The highest ratio of payments to revenues for a single project in the
Intermediate payment case is 2.1 percent, while the lowest ratio is 0.81
percent, depending on the discount rate applied. The average ratio
across all projects in the Intermediate payment case is 1.2 percent and
1.4 percent, applying discount rates of three and seven percent
respectively. The highest ratio of 4.1 percent occurs under the High
payment case assuming a discount rate of seven percent.

**[Initial Regulatory Flexibility Analysis]{.underline}**

MMS is considering the impact of these regulations on small businesses
and may decide to conduct an initial regulatory flexibility act analysis
(IRFA).  A description of the information required for an IRFA is
provided at the end of this report.

# 1.0 Introduction

Increasing the share of electricity generated by alternative sources of
energy is widely recognized as an important element of any strategy to
ensure future supplies of clean, affordable, and reliable power.[^5]
Among the resources available to help achieve this goal are those
associated with the offshore environment, including wind energy, wave
energy, and ocean current energy. Growing interest in the utilization of
these resources to generate electricity has brought into focus the need
for a clear regulatory framework to grant access to Federal submerged
lands where development activities might occur.

The Energy Policy Act (EPAct) of 2005, specifically section 388, amended
the Outer Continental Shelf (OCS) Lands Act to authorize the Secretary
of the Interior to issue leases, easements, or rights-of-way on the OCS
for producing or supporting the production of energy resources other
than oil and gas and to authorize other energy and marine-related
activities that involve the use of existing OCS facilities. The EPAct
also required the Department of the Interior to develop any necessary
regulations to implement this new authority. On March 20, 2006, the
Secretary officially delegated this new authority, and responsibility
for developing any necessary regulations, to the Minerals Management
Service (MMS).[^6] The proposed regulations (Regulation Identifier
Number 1010-AD30, or \"AD30\") would establish a program to allow access
to Federal submerged lands (generally referred to as the Outer
Continental Shelf, or OCS) for alternative energy projects and alternate
uses of existing facilities.

Prior to the passage of the EPAct, the Federal government lacked the
authority to oversee all aspects of alternative energy project
development on the OCS, including siting, construction, operation, and
decommissioning. Additionally, prior to the passage of the EPAct, the
Federal Government lacked the authority to seek payments from private
interests for use of our Nation's OCS. These regulations will provide
the framework for MMS\'s management of an Alternative Energy-Alternate
Use Program. This program will create a system that provides a degree of
regulatory certainty to those proposing, planning, or potentially
financing an offshore alternative energy project on the OCS, as it will
address lease and grant issuance, activity authorization, payment
collection, financial assurance, and project decommissioning.

## 1.1 Need for a regulatory impact analysis

Executive Order 12866, dated September 30, 1993, and amended on January
18, 2007, requires Federal agencies to conduct economic analyses of
significant regulatory actions as a means to improve regulatory decision
making. A regulatory action may be considered \"significant\" if it is
expected to meet one or more of the following conditions.

1.  Have an annual effect on the economy of \$100 million or more or
    adversely affect in a material way the economy, a sector of the
    economy, productivity, competition, jobs, the environment, public
    health or safety, or State, local, or tribal governments or
    communities.

2.  Create a serious inconsistency or otherwise interfere with an action
    taken or planned by another agency.

3.  Materially alter the budgetary impact of entitlements, grants, user
    fees, or loan programs or the rights and obligations of recipients
    thereof.

4.  Raise novel legal or policy issues arising out of legal mandates,
    the President\'s priorities, or the principles set forth in
    Executive Order 12866.[^7]

With respect to AD30:

1.  The regulations would govern an industry that is at an early stage
    of development but which could have developed even without the
    subject regulations. The proposed rule would do two things: it would
    set forth clear regulatory guidelines that facilitate industry
    financing and development, and it would institute payments to the
    Government as a fair return for use of public lands. MMS considered
    three sets of terms for the payments that would be made to the
    Federal government pursuant to these regulations (\"Low,\"
    \"Intermediate,\" and \"High\" cases). As described in Section 5, if
    actual development of OCS alternative energy projects were
    consistent with the scenario presented in this analysis, net Federal
    revenues may exceed \$100 million in some years. However, payments
    to Federal agencies represent a transfer of money from one set of
    entities to another, not the actual effect of the regulations on the
    economy. As anticipated in the EPAct, the new rule would provide for
    an increase in the revenue flow from industry to the Federal
    government and, in some cases, to coastal States, but it would not
    create or prevent industry activities that produce those revenues.
    Furthermore, because the rule does not create these revenues but
    merely causes them to be spent in the government sector instead of
    by the private entities involved, the impact numbers represent an
    extreme upper limit to the effects of the rule on the economy.

2.  The proposed rule would not create a serious inconsistency or
    otherwise interfere with action taken or planned by another agency.
    EPAct granted to the Secretary of the Interior (who delegated to
    MMS) discretionary authority to authorize and regulate alternative
    energy activities on the OCS only to the extent such activities were
    not previously authorized by other applicable law. Therefore,
    through the passage of EPAct, Congress ensured that there would be
    no overlapping areas of Federal jurisdiction on the OCS for
    alternative energy projects.

3.  The proposed rule would not alter the budgetary effects of
    entitlements, grants, user fees or loan programs, or the rights or
    obligations of their recipients.

4.  The proposed rule [would]{.underline} raise novel legal or policy
    issues because the rulemaking would establish a new regulatory
    program for the development of alternative energy resources on the
    OCS and for the alternate use of existing OCS facilities. For this
    reason, it has been determined that AD30 is a significant rule
    requiring further economic analysis.

Primarily for the reason that the proposed rule would raise novel legal
or policy issues, MMS is required to conduct an economic analysis of
AD30.

## 1.2 Scope of the analysis

Discussions between MMS and OMB resulted in a determination that the
appropriate analysis of the proposed rulemaking is one that focuses on
the fiscal impacts of the rule. While fiscal revenues (i.e., the
revenues the Federal government will receive due to economic activity
that occurs under this rule) are traditionally considered a transfer
payment, in this analysis they are treated as a \"benefit.\" The cost
side of the analysis comprises the Federal government\'s costs to
implement the program that will administer the proposed rules. In
addition, as required by the Regulatory Flexibility Act (RFA) of 1980
(as amended by the Small Business Regulatory Enforcement Fairness Act of
1996 (SBRFA) and Executive Order 13272 ("Proper Consideration of Small
Entities in Agency Rulemaking")), this analysis considers whether the
fiscal payments made by the developers of regulated projects to MMS will
significantly affect a substantial number of small entities.

The time period for the analysis is 2008-2027. More specifically, the
analysis includes Federal program costs and revenues that (1) are
associated with projects that become operational during this period and
that (2) are incurred or collected during this period. In other words,
the stream of costs and revenues that would occur in connection with a
project that has a lifetime extending beyond 2027 is truncated, for the
purposes of this analysis, at 2027. The technical scope of the analysis
(with respect to alternative energy projects) includes wind energy, wave
energy, and ocean current energy projects. The geographic scope of the
analysis includes the OCS on the Atlantic and Pacific coasts and in the
Gulf of Mexico, but does not include the waters off Alaska and Hawaii.

## 1.3 Description of the baseline and alternative

The baseline condition, against which the impact of the proposed rule is
to be compared, is a continuation of the regulatory regime that existed
prior to the EPAct, under which the Army Corps of Engineers (Corps)
assumed principal responsibility for reviewing and permitting wind
energy projects and the Federal Energy Regulatory Commission (FERC)
asserted authority for wave and ocean current projects on the OCS. For
the purposes of this analysis, we assume that the project development
forecast is independent of the regulatory regime; the locations, types,
and timing of development would be the same with or without the MMS
program contemplated by the EPAct.[^8] MMS is considering only one
alternative to the baseline---a regulatory program under which MMS
grants property rights, collects payments for activities conducted on
the OCS, and establishes a comprehensive "cradle-to-grave" regulatory
program for authorizing alternative energy activity---but has developed
three different cases with varying payment terms (\"Low,\"
\"Intermediate,\" and \"High\"). Section 4 provides a detailed
description of the three payment cases. The main analysis provides a
single scenario, or set of results based on identical assumptions
regarding electricity prices and other conditions, for each payment
case. Other scenarios based on the same payment cases are presented in
Appendix B and Appendix D.

## 1.4 Report outline

The remainder of this report is organized as follows.

-   Section 2 presents a general forecast of alternative energy
    development on the OCS during the period 2008-2027. Based on
    available literature, input from third party experts, and
    professional judgment, the section concludes with a forecast of
    individual projects by technology, location, and first year of
    operation.

-   Section 3 describes the calculation of annual and cumulative
    estimated costs to the Federal government to implement the MMS
    program that will regulate the use of the OCS for alternative energy
    projects and the alternate use of existing OCS facilities.

-   Section 4 generally describes the cash flow model constructed to
    analyze the feasibility of projects in the development forecast and
    to produce estimates of the transfer payments (i.e., the Federal
    revenues) that would result from the projects included in the
    development forecast. This section also provides additional detail
    concerning the alternative energy development forecast, including
    descriptions of the various assumptions (technology- and
    market-specific) that were made to complete the quantitative
    estimation of costs and revenues.

-   Section 5 discusses the sensitivity of model results to specific
    input assumptions and presents analytical results showing the effect
    of renewable energy certificates on project viability.

-   Section 6 presents an alternative set of results that illustrate the
    impact of the Federal production tax credit on project viability.

-   Section 7 presents the results from the cost and transfer payment
    analyses and reports annual and cumulative estimates of the net
    revenues associated with the proposed rule. This section also
    presents summary results categorized by technology and by geographic
    region.

-   Section 8 provides a qualitative analysis of costs and revenues
    associated with possible alternate uses of existing OCS facilities.

-   Section 9 discusses and presents an analysis of the distributional
    impacts, as required by the RFA/SBRFA and Executive Order 13272
    ("Proper Consideration of Small Entities in Agency Rulemaking").

-   Appendix A provides a more detailed description of the model
    constructed to estimate Federal revenues and costs.

-   Appendix B provides electricity production and financial performance
    information for projects in the development forecast that would be
    operational by 2027.

# 2.0 forecast of alternative energy development on the outer continental shelf

The analysis of program management costs and projected transfer payments
to the Federal treasury between 2008 and 2027 depends on a forecast of
the number and type of OCS alternative energy projects that might
generate Federal costs and revenues during that period. Creation of such
a forecast is subject to considerable uncertainty, as these will be the
first projects of their kind in United States waters and will be
entering a market that is, and will continue to be, evolving. For the
purposes of this rulemaking, a forecast is constructed using information
about existing project proposals, market and technology research, and a
general presumption that regulatory, technical, and financial conditions
during the period of analysis will support rather than constrain
development activity.

While our focus was on projects that could begin generating electricity
by 2027, our forecast must extend nine years beyond that (based on the
presumed period from project application to electricity generation, as
described in Section 4) to account for projects that will be \"in
process\" (i.e., that will result in the Federal government incurring
program costs and that will pay pre-operational fees to the Federal
government).

It is very important to note that the forecast developed for this
analysis includes details (general project locations, types, and sizes)
that are necessary for a complete cost-benefit analysis but that are not
meant to be indicative of any Federal government preferences, plans, or
intentions with regard to OCS alternative energy development. While the
forecast represents one possible development path (i.e., one
\"scenario\"), a combination of market and government factors will
ultimately determine the type, scale, and timing of actual activity.

In order to ensure the development of a reasonable forecast, we
collected and reviewed readily available literature and other sources of
information that address one or more elements relevant to future
development of OCS renewable energy. As directed by MMS, we focused on:

-   Estimates of renewable energy resources on the OCS;

-   Descriptions of existing and planned renewable energy generation
    technologies that might be deployed on the OCS;

-   Estimates of cost trends over time for different renewable energy
    technologies;

-   Estimates of when different technologies are expected to be
    \"economically deployable\";

-   Estimates of OCS renewable energy generating capacity expansion on
    an annual or semi-annual basis; and

-   Discussions about the integration of OCS electricity generation into
    the onshore transmission grid.

In general, we found relatively little information that describes in any
detail potential development over the next 20 years. Therefore, the
development scenario that serves as the basis for the fiscal impact
analysis is constructed from available information (including the
preliminary MMS forecast) and a set of assumptions such that the
resultant projects can be described as both technically reasonable and
economically viable (i.e., profitable, subject to the limitations of the
assumptions required to assess future economic viability). The following
sections describe our findings with respect to each of the above
elements, differentiated by resource, as appropriate. The final section
describes how we constructed the development forecast.

## 2.1 Renewable energy resources on the OCS

The amount of energy contained in the wind, waves, and ocean currents
that exist within the area subject to federal jurisdiction is vast.
Several efforts have been undertaken in recent years to quantify the
wind and wave energy potential in different coastal regions. The amount
of energy contained in ocean current resources located in federal waters
is less well-defined; estimates produced during the 1970s are the best,
readily available indications of the scale of this resource.

### 2.1.1 Wind 

Musial and Butterfield (2004) developed a detailed estimate of wind
resources at a distance of five to 50 nautical miles (nm) offshore in
key Atlantic and Pacific coastal regions. Although this estimate
excludes part of MMS\'s jurisdictional area (three to five nm and 50 to
200 nm) as well as the Southeast and Gulf of Mexico regions, it captures
the area where substantial development can be anticipated to occur
through 2027. Table 2-1 presents the results of this analysis. Note that
for the zone between five and 20 nm offshore, two-thirds of the area is
excluded from the estimate to account very conservatively for
restricting factors such as environmentally sensitive habitats and
viewshed conflicts. Similarly, one-third of the area between 20 and 50
nm offshore is excluded (the lower number reflecting the assumption that
there would be fewer environmental or viewshed issues at a greater
distance from shore). The Department of Energy has more recently
developed a refined internal analysis of offshore wind energy resources,
as summarized in Table 2-2.

Table 2-1

Estimate of U.S. Offshore Wind Energy Resources (Megawatts) by Region
and Water Depth

  -------------- ----------------- ------------- ----------------- -------------
                 **5 - 20 Nautical               **20 - 50         
                 Miles**                         Nautical Miles**  

  **Region**     **Shallow \<30    **Deep**      **Shallow \<30    **Deep**
                 meters**                        meters**          

  New England    9,900             41,600        2,700             166,300

  Mid Atlantic   46,500            8,500         35,500            170,000

  California     2,650             57,250        0                 238,300

  Pacific        725               34,075        0                 93,700
  Northwest                                                        

  **Totals**     **59,775**        **141,425**   **38,200**        **668,300**
  -------------- ----------------- ------------- ----------------- -------------

Source: Musial, W. and S. Butterfield, "Future for Offshore Wind Energy
in the United States," NREL/CP-500-6313, June 2004.

Table 2-2

DOE Estimate of U.S. Offshore Wind Energy Resources

by North American Electric Reliability Corporation Region

(Megawatts, Class 5+, \>3 nautical miles offshore)

  --------------------- ---------------- ------------------ --------------
                        **Water Depth**                     

  **Region**            **Shallow (\<    **Transitional     **Deep (\>
                        30m)**           (30-60m)**         60m)**

  New England           9,100            117,590            32,500

  New York              1,680            33,240             29,400

  Mid Atlantic (NJ, DE, 17,645           10,000             67,115
  MD)                                                       

  Southeast (VA-GA)     10,105           20,955             23,560

  California            25               210,535            280

  Pacific Northwest     0                176,780            1,615

  **Totals**            **38,555**       **569,100**        **154,470**
  --------------------- ---------------- ------------------ --------------

Source: Chris Namowicz, Energy Information Administration, personal
communication, April 2, 2007.

Other studies have looked at the wind resource potential in specific
areas, and support the conclusion that the wind resource will not be a
constraint on future development.

-   Kempton et al (2007) examined the wind resource in the
    Middle-Atlantic Bight (from Massachusetts to North Carolina) and
    determined that it has the potential to deliver approximately 330
    gigawatts (GW) of power (based on a nameplate capacity of 835 GW and
    an average capacity factor of 39.5 percent). This study does not
    separate resources that are less than three nm from shore from those
    that are more than three nm from shore.

-   AWS Scientific, Inc. (2002) conducted a preliminary assessment of
    Long Island\'s offshore wind energy resource. AWS estimates that the
    area that is at least three miles offshore, has a water depth of
    less than 30 meters, and exhibits average wind speeds greater than
    eight meters per second could support up to 5,200 megawatts (MW) of
    generating capacity.

-   A 2004 study by Atlantic Renewable Energy Corporation (AREC) and AWS
    Scientific of New Jersey\'s offshore wind energy development
    potential concluded that the State had a maximum theoretical
    potential of 24,500 MW of offshore wind energy, largely in waters
    more than three miles from shore (AREC and AWS 2004).

-   An analysis by Stanford University researchers (Dvorak et al. 2007)
    concluded that existing and next-generation support structure
    technology (enabling development in up to 50 meters of water) could
    support the development of more than 3,000 MW of wind energy
    capacity off the northern California coast (assuming Class 5 winds).
    More than 20,000 MW of additional capacity is estimated to be
    potentially available if development could occur in waters between
    50 and 200 meters in depth.

-   A 2007 presentation by AWS Truewind LLC (formerly AWS Scientific)
    (Freedman 2007) summarized the analysis of offshore wind energy
    potential in the coastal zone off North Carolina, South Carolina,
    and Georgia. AWS estimated that the resource potential is in the
    tens of thousands of megawatts, with a \"substantial amount\" of
    this potential in shallow (\< 50 foot depth) waters.

### 2.1.2 Wave 

The Electric Power Research Institute\'s (EPRI) Ocean Energy Program
estimates the combined wave energy resource in four U.S. regions
(Washington/Oregon/California, New England/Mid-Atlantic, southern
Alaska, northern Hawaii) to be approximately 2,100 terawatt-hours (TWh)
per year (based on a minimum mean power flux of 10 kilowatts per meter;
a mean flux less than 10 kW/m is highly unlikely to be considered an
economically viable resource) (Bedard 2007). EPRI further assumes that
15 percent of this energy can be converted to mechanical energy, that
wave energy conversion devices will operate at 90 percent efficiency,
and that they will have a 90 percent availability, resulting in an
estimate of approximately 260 TWh of available energy per year. The
resources in the continental U.S. (the Atlantic and Pacific coast
regions) are estimated to be approximately 67 TWh per year, or 25
percent of the total. This is equal to a capacity of approximately 7,600
MW. Approximately 80 percent of the continent-specific resource is
associated with the region off the Washington, Oregon, and California
coasts.

### 2.1.3 Ocean current 

OCS development of ocean current resources is likely limited to the
Florida Current, which flows between Florida and the Bahamas. Estimates
of the energy present in the Florida Current date back to the mid-1970s,
when the use of this resource for electricity generation was first
proposed. While these early studies indicate an energy flux of as much
as 25,000 MW through a single cross-sectional area, the amount of energy
that could be extracted is uncertain, primarily because of concerns that
reducing the energy in this portion of the Gulf Stream could have
negative environmental consequences. Early modeling suggested that an
array of turbines totaling 10,000 MW of capacity would not reduce the
current\'s speed by more than what has been observed as its natural
variation, and thus might be feasible (Lissaman and Radkey 1979;
Charlier and Justus 1993). Further investigation is required to
determine the magnitude of the technically available resource.

## 2.2 Renewable energy generation technologies

Based on more than 20 years of onshore deployment in the U.S., as well
as several years of experience in the offshore environment in Europe,
wind power technologies (and the technical issues that future offshore
development will face) are well defined. A summary is provided below
with a focus on issues relevant to forecasting the development of
offshore wind energy capacity. Wave energy and ocean current energy
technologies are far less mature in their development. In these cases,
we provide only a descriptive summary of the technologies that appear to
be most likely to be deployed first on a commercial scale.

### 2.2.1 Wind

The primary components of an offshore wind energy project are the wind
turbine (the nacelle and rotor assembly), tower, foundation,
intra-project electricity collection system (i.e., cables and offshore
substation), and project-to-shore transmission cabling. The turbine and
tower are relatively mature technologies, with offshore components
differing from their onshore analogues primarily in scale. Foundations
and transmission comprise the key differences between onshore and
offshore wind energy technology.

Offshore wind farms constructed in the 1990s (all in Europe) utilized
wind turbines rated at 450 to 600 kW. The second generation of European
offshore wind farms, constructed since 2000, have utilized turbines
rated at 1.5 to 3.6 MW. Projects developed over the period of this
analysis can be expected to utilize turbines in the 3.6 to 5 MW range,
though even larger scale machines (perhaps up to 10 MW) are in
development. Site-specific capacity factors will depend on the turbine
that is matched to the resource at each project site. However, the
typical range for offshore wind farms is 35 to 40 percent; we assume a
fixed capacity factor of 38 percent for all wind projects in the
development forecast. Based on the first projects and proposals, it can
be assumed that the rated capacity of offshore wind projects will range
from 150 MW to 1,000 MW or more.

The most important technological (and cost) consideration for future
offshore wind energy development is the type of support structure used,
especially as development is considered for deeper waters, where much of
the available resource is located. All offshore development to date has
occurred in relatively shallow waters (5-18 m depth) using monopile and
concrete gravity base foundations. These types of foundations are
generally appropriate (i.e., economic) to a depth of approximately 30 m.
At \"transitional\" depths (up to approximately 60 m), support
structures will necessarily begin to look more like those used in the
offshore oil and gas industry, with wider bases and multiple anchor
points. In the long term, the use of floating platforms would enable
maximum exploitation of the offshore wind resource. Floating platforms
will need to have sufficient buoyancy to support the weight of a large
turbine while also countering the effects of wind and wave motion
(pitching, rolling, heaving). Development of floating platforms is at an
early stage, but will benefit from the experience of the oil and gas
industry. As Musial and Butterfield (2004) described, floating wind
turbine platforms will have several design and cost advantages over the
floating platforms used for oil and gas exploration and production,
including:

-   Deployment in much shallower water than is common for oil and gas
    structures; and

-   Minimal above-water deck area requirements compared to oil and gas
    platforms, resulting in an ability to submerge more of the structure
    and minimize the area subject to wave loading.

A discussion of issues related to the transmission of electricity from
an offshore project to the onshore grid is provided below.

### 2.2.2 Wave

As of April 2007, EPRI had identified 32 companies or organizations
(e.g., academic institutions) in the United States, Europe, and
Australia that are currently developing wave energy conversion
technology. In general, these technologies fall into one of five
categories based on the way in which they harness the wave energy:

-   Oscillating water column - a partly submerged structure with air
    trapped above the surface of an enclosed water column. The water
    column acts as a piston, driving air through a turbine, as waves
    enter and exit the structure.

-   Overtopping - a structure that allows waves to enter a reservoir at
    the bottom of which are hydroelectric turbines. Water flowing out of
    the reservoir turns the turbines and generates electricity.

-   Symmetrical point absorber - a bottom-mounted or floating structure
    that absorbs energy in all directions and converts this energy to
    electricity. Power take-off from a point absorber can take a number
    of forms.

-   Terminator - a floating structure that absorbs energy in a single
    direction (i.e., is oriented normal to the wave direction). As with
    point absorbers, power take-off can take a number of forms.

-   Attenuator - a floating structure, oriented parallel to wave
    direction, that translates the movement of the waves along its
    length into energy.

The development stage of the identified technologies ranges from
lab-scale proof-of-concept to full-scale field demonstration and
commercial development. Among the more advanced technologies are:

-   AquaBuoy, a floating point absorber developed by the AquaEnergy
    Group Ltd. (a division of Finavera Renewables). An AquaBuoy project
    is in development near Makah Bay, WA.

-   The Oceanlinx (formerly Energetech) oscillating water column device,
    a 500kw prototype of which has been successfully deployed in
    Australia.

-   The Archimedes Wave Swing, a seabed-mounted point absorber developed
    by AWS Ocean Energy. A full-scale AWS unit has been installed and
    tested off the coast of Portugal.

-   The Pelamis, a free-floating hinged contour attenuator device
    developed by Ocean Power Delivery. Deployment of the first
    commercial scale units (with a total capacity of 2.25 MW) began off
    the Portugal coast in 2006.

-   The PowerBuoy, a floating point absorber developed by Ocean Power
    Technologies. The PowerBuoy was successfully tested off the New
    Jersey coast during a 12-month field trial that ended in
    October 2006. The planning phase of a commercial project off the
    Spanish coast has also recently been completed.

It is not possible to predict whether these will be the technologies
that account for all or most of the wave development activity that
occurs in the next 20 years. A 2004 EPRI review of wave energy
conversion devices assumes capacity factors ranging from 20 to 50
percent depending on the technology (Previsic 2004a).[^9] For the
purpose of our analysis we apply a capacity factor of 35 percent to all
wave energy projects in the development forecast. Based on early project
proposals, it can be assumed that the rated capacity of offshore wave
projects during the period of analysis will range from 50 MW to 100 MW.
To simplify the analysis, we initially assume a standard size of 75 MW
for all projects in the development forecast.

### 2.2.3 Ocean current

Available information indicates at least two technologies proposed for
use in harnessing the energy contained in the Florida Current.

-   The SeaGen twin rotor turbine, developed by Marine Current Turbines
    Limited and licensed for use in U.S. development projects by Ocean
    Renewable Power Company (dba Red Circle Systems Corporation). The
    SeaGen unit operates much like a wind turbine and is secured to a
    monopile foundation in the seafloor. Sea trials of this technology
    have occurred in the waters off the United Kingdom.

-   The Open Hydro concept, an open-center turbine comprising a
    self-contained, disc-shaped rotor with a solid state permanent
    magnet generator enclosed within a fixed outer rim. Each turbine is
    expected to be mounted on the seafloor with a gravity base.

The first proposals for ocean current energy production on the
continental U.S. OCS (i.e., in the Florida Current) suggest total rated
capacities of 20-40 MW. We do not have additional information with which
to estimate the likely scale of ocean current projects during the period
of analysis, so we assume a constant size of 30 MW per project. Given
the constant flow in the current, we assume a relatively high capacity
factor of 80 percent for each project.

## 2.3 Renewable energy technology cost trends

### 2.3.1 Wind

Substantial work has been undertaken to forecast cost reductions for
offshore wind energy. In general, these reductions will result from a
combination of \"learning\" and economies of scale. Learning is usually
expressed as a \"progress ratio\" (PR) that indicates a percentage
reduction in costs for each doubling of cumulative capacity
(industry-wide). For example, a PR of 90 percent indicates a 10 percent
reduction in costs for each capacity doubling. Several studies have
addressed the issue of future cost reductions for offshore wind energy.

Junginger et al. (2004) examined the potential for cost reductions
related to specific elements of the initial investment costs associated
with offshore wind farms and arrived at the conclusion that these costs
could decline by 25 to 39 percent by 2020. This reduction reflects the
cumulative effect of (1) potential reductions in wind turbine costs (at
a PR of 81 to 85 percent); (2) the potential increased use of high
voltage direct current (HVDC) cables to transmit electricity to the
onshore grid from more distant offshore locations (at a PR determined to
be 62 percent); (3) reductions in the cost of HVDC converter stations
(PR equal to 71 percent); and (4) reductions in the costs of tower and
foundation installations (PRs of 77 and 95 percent, respectively).

Junginer et al. (2005) also used data from the United Kingdom and Spain
to create a global experience curve for wind energy (onshore and
offshore), in which the focus was on total project costs rather than
just the cost of the wind turbines. The results of their analysis
suggest a global progress ratio in the range of 77 to 85 percent, with
an average of 81 percent. The authors note, however, that development of
a global ratio carries with it certain limitations. For example, while a
global market for wind turbines exists, other components may depend more
highly on local factors that give rise to different, location-specific
learning effects.

Coulomb and Neuhoff (2006) used an engineering-based model to examine
cost changes as a function of turbine size using 1,500 individual
observations from the period 1991 to 2003. After incorporating a
correction for the fact that larger turbines produce more energy per
installed megawatt, they concluded that wind turbine costs have
decreased by 12.7 percent with each doubling of capacity.

Other than Junginger et al. (2004), most examinations of cost reductions
of wind energy do not focus exclusively on offshore development. As
Garrad Hassan (2003) note, several factors must be considered before
applying PRs based on onshore experience to offshore projects,
including: the marine-based cost elements that do not apply to onshore
wind; the relative immaturity of some offshore cost elements, suggesting
that initial cost reductions may be more rapid than the current onshore
PR would suggest; and the larger scale of offshore wind projects.

A recent study of the costs of offshore wind energy (ODE 2007) suggests
there is ample room for cost reductions. Using a \"typical\" 108 MW (30
x 3.6 MW) project as its base, the ODE model predicts a two to three
percent capital cost increase through 2010 followed by a reduction of up
to 30 percent by 2018, at which point costs begin to plateau. ODE
further predicts a reduction in operation and maintenance (O&M) costs
from the current expectation of approximately 23 percent of capital
costs, though it does not specify the magnitude or timing of the
anticipated reduction.

For this analysis, we developed projections for wind energy capital
costs over time for projects of varying sizes based on the assumption
that larger projects will always exhibit economies of scale and that
learning effects will reduce all costs over time. First, we used cost
data for the 108 MW project described in the ODE (2007) report and for
two projects (30MW and 200 MW) described in a report prepared for the
State of Rhode Island (ATM 2007) to construct a trendline for projects
between 100 MW and 1,000 MW. We then assumed three doublings of global
capacity between 2008 and 2018 with a conservatively estimated 10
percent reduction in costs for each doubling. We believe this capacity
growth trend is reasonable given the number and scale of projects
currently in development in Europe. Table 2-3 presents the results of
our analysis for the three size classes that we use in our forecast.

Table 2-3

Assumed Capital Costs (per kW) for U.S. Offshore Wind Energy
(2007\$)[^10]

  -------------- ------------------ ------------------ ------------------
  **Period**     **Project Size                        
                 (MW)**                                

                 **150**            **500**            **1000**

  2008 - 2011    \$3,200            \$2,700            \$2,100

  2012 - 2015    \$2,900            \$2,400            \$1,900

  2016 - 2019    \$2,600            \$2,200            \$1,700

  2020 - 2027    \$2,300            \$2,000            \$1,500
  -------------- ------------------ ------------------ ------------------

### 2.3.2 Wave

Given its relative immaturity and lack of development to date, far less
work has been undertaken to project cost trends for wave energy
technologies. However, it can be expected that they will eventually
follow trajectories similar to those that have reduced the costs of
onshore and offshore wind. Bedard (2007) suggests that the progress
ratio for wave energy technology will be 82 percent and that a 90 MW
Pelamis project with a 38 percent capacity factor could achieve economic
competitiveness with onshore wind at cumulative global capacities of 15
GW (for a Hawaii or northern California location), 20 GW (for an Oregon
location), or 40 GW (for a Massachusetts location).

Gumerman and Marnay (2004) describe an approach for considering
learning-based cost reductions associated with initial commercialization
of new technologies. The first units of such technologies often cost
more than anticipated, resulting in the need to assign a \"technological
optimism factor\" (TOF), or cost premium, to these units. Technological
optimism learning is the process by which this factor is eventually
eliminated. As Gumerman and Marnay describe, the National Energy
Modeling System (NEMS) has previously applied TOFs of five to ten
percent to four technologies (fuel cells, biomass, solar thermal, and
photovoltaics), with the premium eliminated upon construction of the
fifth commercial plant. A similar trend might be expected for the first
commercial wave and ocean current plants.

Total capital costs for wave energy projects will certainly vary by
technology. However, the only reliable estimate we have for wave energy
capital costs comes from EPRI\'s assessment of a hypothetical
commercial-scale project off the Oregon coast (Previsic 2004b). This
analysis assumes an array of 180 Pelamis units with a total rated
capacity of 90 MW. The total installed cost for this project is
calculated to be approximately \$215 million, indicating a unit cost of
approximately \$2,400 per kW. We propose to use this value as a base and
apply Gumerman and Marnay\'s as well as Bedard\'s learning assumptions
(i.e., an initial premium, in our case an assumed initial capital cost
of \$2,600, followed by subtraction of the premium and then an 18
percent cost reduction for each additional doubling of capacity) to
estimate future capital costs. We do not have estimates of global wave
energy capacity growth that would allow us to predict when capacity
doublings might be achieved, and therefore must make what we believe are
reasonably conservative assumptions. Table 2-4 provides our assumed
capital cost schedule, which reflects three doublings during the period
of analysis.

Table 2-4

Assumed Capital Costs for U.S. Offshore Wave Energy (2007\$)

  ----------------------------------- -----------------------------------
  **Period**                          **Capital Cost (\$/kW)**

  2008 - 2011                         \$2,600

  2012 - 2015                         \$2,400

  2016 - 2019                         \$1,970

  2020 - 2023                         \$1,615

  2024 - 2027                         \$1,325
  ----------------------------------- -----------------------------------

### 2.3.3 Ocean current

We are not aware of readily available data describing capital costs or
anticipated cost reductions for ocean current energy. We therefore
assume costs equal to those described above for wave energy.

## 2.4 Renewable energy economics

Readily available information does not provide estimates of the point at
which wind, wave, or ocean current technologies will be \"economically
deployable.\" As with any power generation technology, offshore
renewables will be economically competitive when they can produce
electricity at a cost that is less than or equal to onshore
alternatives. Thus, competitiveness will be driven by factors that
reduce the cost of electricity from offshore renewables and/or increase
the cost of electricity from the onshore alternatives. As discussed
above, the former includes capital and O&M cost reductions resulting
from learning, economies of production scale, and research and
development of advanced (lower cost) technologies, as well as government
interventions (i.e., subsidies) that effectively lower the cost of
electricity. Factors that can increase the costs of onshore alternatives
include rising fuel costs and government actions. The economic
competitiveness of offshore renewables is highly project- or
location-specific. With subsidies, offshore renewable energy projects
(particularly wind energy projects) can already be competitive, in
general, when they are feeding into markets with relatively high
electricity prices.

As described later in this report, we used a cash flow model,
constructed for the purpose of estimating payments to the Federal
government under the terms of the proposed regulations, to assess, based
on selected performance criteria, whether or not a project should be
considered economically feasible.

## 2.5 Renewable energy capacity expansion

Readily available information does not provide annual or semi-annual
estimates of renewable energy generation capacity expansion on the OCS.
For context, however, several sources discuss the overall potential for
capacity growth in the near- to medium-term.

-   Garrad Hassan (2003) projected the annual and cumulative growth of
    offshore wind energy capacity on a global basis, with cumulative
    capacity approaching 43 GW by 2020. During this period, Garrad
    Hassan assumed annual installations would increase each year, from
    0.8 GW in 2004 to 8.9 GW in 2020.

-   The European Wind Energy Association (2006) has established targets
    for the development of onshore and offshore wind energy in Europe.
    The current targets for cumulative offshore wind energy are 10 GW by
    2010, 70 GW by 2020, and 150 GW by 2030.

-   Musial et al. (2006) described a \"moderately aggressive development
    scenario\" that could result in the development of 50 GW of offshore
    wind energy capacity in the United States by 2026 (including
    development in OCS and non-OCS areas), with additional development
    resulting in another 50 GW of capacity by 2036. Based on personal
    communication with Musial, we believe it is reasonable to assume
    that approximately one-half of the offshore wind energy capacity
    development over the next 20 years (i.e., 25 GW) will occur in OCS
    areas.

In addition, EPRI ocean energy experts have developed an \"optimistic\"
scenario for wave energy capacity development in the United States,
resulting in approximately 15 GW of new capacity by 2020 (Table 2-5;
Bedard 2007).

Table 2-5

EPRI \"Optimistic\" Forecast of U.S. Wave Energy Capacity Development

  ----------------------- ----------------------- -----------------------
  **Year**                **Annual (MW)**         **Cumulative (MW)**

  2008                    3                       3

  2009                    1                       4

  2010                    80                      84

  2011                    130                     214

  2012                    300                     514

  2013                    500                     1,014

  2014                    800                     1,814

  2015                    1,200                   3,014

  2016                    1,700                   4,714

  2017                    2,500                   7,214

  2018                    2,600                   9,814

  2019                    2,600                   12,414

  2020                    2,600                   15,014
  ----------------------- ----------------------- -----------------------

Source: Roger Bedard, EPRI, personal communication, April 16, 2007.

However, it is important to note that, according to Bedard, a
significant amount of this development is forecast to occur in Alaska
and Hawaii and in nearshore (non-OCS) waters, suggesting much less
development that would be subject to MMS regulation.

We are unaware of any forecasts of the growth of ocean current energy
over the next 20 years.

## 2.6 Integration of OCS electricity generation into transmission networks

During the period of analysis, the most significant transmission-related
issues will be those associated with the development of offshore wind
energy capacity, given both the scale of potential projects and their
potential distance from shore. At approximately 20 percent of total
project costs (exceeded only by turbine and support structure costs),
the ability to collect electricity from multiple offshore wind turbines
and transmit that electricity to the onshore grid cost-effectively will
be an important determinant of the pace of future development.

Wright et al. (2002) note that the United States\' substantial
experience laying submarine cables is not directly applicable to
offshore wind farms; oil and gas platforms, for example, require much
lower voltage power, while providing electricity to an island from an
onshore source utilizes medium- to high-voltage cables that only deliver
power *to* a load rather than *from* a source of generation. In
addition, they noted the lack of domestic manufacturers of high-voltage
cable and, in comparison to Europe, the relative lack of experience and
equipment for cable installation. We assume that the market would
address these issues given sufficient and sustained growth in offshore
wind energy, and that gains in experience would benefit other forms of
offshore renewable energy as well.

Green et al. (2007) provide a simple model of the cost and performance
of offshore wind farm electrical (i.e., collection and transmission)
systems. Addressing the issue of alternating versus direct current
transmission to shore, they note the current consensus that high voltage
alternating current (HVAC) will be preferred on economic grounds up to a
transmission distance of 50 km, while high voltage direct current (HVDC)
will not be consistently more cost-effective before transmission
distances reach at least 80 km. Between 50 and 80 km, the costs of HVAC
and HVDC are expected to be comparable. Wright et al. suggest that
HVDC\'s economies of scale will make it the preferred option as projects
exceed 200 MW and at least 50 km from shore, and that the prospect of
large, inter-regional offshore HVDC networks might eventually serve as
cost-effective \"substations\" for offshore wind. Finally, Green et al.
note that current cable designs may prove inadequate for use with
floating wind turbine platforms, as they are not designed to withstand
the various forces that will act on them if they are not laid on, or
buried in, the seafloor. This could also be a concern for wave and ocean
current energy projects.

## 2.7 Conclusions

The purpose of our review of readily available information was to
determine whether, and if so how, this information should factor into
the project development forecast that serves as the foundation for the
fiscal impact analysis. The forecast must specify the number, type,
size, and general location of OCS projects that are submitted for MMS
review or that become operational during the period 2008 through 2027.
In reality, the number, type, size, and location of OCS alternative
energy projects will be driven by economic considerations. Our
preliminary forecast is based on non-economic considerations---that is,
it considers what might be reasonable given presumed physical and
technical constraints. As described in Section 4, we use a financial
model to determine whether each project in the preliminary forecast
appears to be economically viable (given the assumptions used in the
model).

Based on our review of available information as well as conversations
with Roger Bedard (EPRI) and Walt Musial (NREL), we drew several
conclusions to carry forward to the specification of a preliminary OCS
development forecast, which we constructed in two parts. The first part
describes projects that would become operational by 2027. The second
part covers projects that would become operational after 2027, but would
be in development during the 2008-2027 period. The following are
assumptions relevant to the construction of the first part of the
forecast.

-   Offshore wind energy will dominate OCS development activity, both in
    terms of projects and generating capacity.

-   The significant majority of offshore wind development will occur in
    the Atlantic region. Development in the Gulf of Mexico will likely
    be focused on Texas State submerged lands in the near term (given
    the 3 marine league, or 9 nm, State submerged land boundary). Gulf
    of Mexico wind projects begin to appear in the later years of the
    forecast to reflect the long-term potential for deeper-water
    projects that are further from shore. In the Pacific region, where
    shallower water depths extend a relatively short distance from
    shore, development will likely focus in the near-term on
    smaller-scale demonstrations of floating support structure
    technology. Larger-scale, commercial projects could emerge in the
    Pacific region later in the period of analysis with the maturation
    of floating support structure technology. Several California
    offshore wind projects are included in the forecast to reflect this
    possibility.

-   All wave projects will be located in the Pacific region; all ocean
    current projects will be located off the Florida coast.

-   Assuming 25 GW of total capacity (see above) and an average of 500
    MW per wind energy project (some may be as large as 1,000 MW+, but
    others will be in the 150-500 MW range), suggests a total of
    approximately 50 individual wind energy projects. \[In comparison,
    the 15 projects granted development licenses in the UK Round Two
    offer average 478 MW each.\]

```{=html}
<!-- -->
```
-   MMS provided IEc with an assumed ratio of project types (17 wind:3
    wave:5 current) for use in forecast development. Using this ratio,
    50 wind projects suggests development of nine wave projects and 14
    ocean current projects during the period of analysis (a total of 76
    individual projects).

-   No other generation will occur until 2018, reflecting MMS
    consideration of new project applications beginning in 2009.

-   A large number of projects will begin generation during the period
    2019-2022, driven in part by an anticipated lease sale in 2012.

-   Between 2023 and 2027, the rate at which new projects begin
    electricity generation will slow, reaching a steady state of three
    per year.

The post-2027 period includes three new projects per year for nine
additional years, or 27 projects (for a total of 103 projects with some
degree of development activity during the period 2008-2027). Maintaining
the same ratio of project types, this suggests an additional 19 wind
projects, three wave projects, and five ocean current projects.

We distributed the 103 projects in our initial forecast temporally and
geographically over the 2008-2036 period using professional judgment and
the above assumptions (the year to which each project is assigned
indicating the year in which electricity generation begins). Wind
projects were assigned a generic capacity of either 150, 500, or 1,000
MW. All wave projects that are assumed to become operational by 2027
were assigned a capacity of 75 MW, increasing to 150 MW from 2028-2036.
All ocean current projects that are assumed to become operational by
2027 were assigned a capacity of 30 MW. Ocean current projects that are
assumed to become operational between 2028 and 2036 were assigned
capacities of 60 MW.

The resultant preliminary forecast is presented in Table 2-6. Table 2-7
categorizes the projects in the initial development forecast by type and
region. Section 4 describes our methodology for selecting the
hypothetical projects from among our initial forecast universe that
warrant inclusion in the calculation of estimated Federal revenues and
costs (a combination of a financial viability test and an assumed
drop-out rate for non-financial reasons).

Table 2-6

Preliminary OCS Development Forecast, 2008-2036\*

  ----------------------------------------------------------------------------
  **Year\*\***   **Location**               **Type**          **Capacity**
  -------------- -------------------------- ----------------- ----------------
  **2008**       \-\--                      \-\--             \-\--

  **2009**       \-\--                      \-\--             \-\--

  **2010**       \-\--                      \-\--             \-\--

  **2011**       \-\--                      \-\--             \-\--

  **2012**                                                    

  **2013**       New England                Wind              500

                 New York                   Wind              150

  **2014**       \-\--                      \-\--             \-\--

  **2015**       \-\--                      \-\--             \-\--

  **2016**       \-\--                      \-\--             \-\--

  **2017**       Mid-Atlantic               Wind              150

                 Mid-Atlantic               Wind              500

                 Mid-Atlantic               Wind              150

                 New England                Wind              500

                 New England                Wind              150

  **2018**       Mid-Atlantic               Wind              500

                 New England                Wind              500

                 New York                   Wind              150

                 New York                   Wind              500

                 Southeast                  Wind              150

                 California                 Wave              75

                 California                 Wave              75

                 Oregon                     Wave              75

                 Oregon                     Wave              75

  **2019**       Mid-Atlantic               Wind              150

                 Mid-Atlantic               Wind              150

                 Mid-Atlantic               Wind              500

  **2019         New England                Wind              500
  (cont.)**                                                   

                 Southeast                  Wind              150

                 California                 Wind              150

                 California                 Wind              150

                 Florida                    Current           30

                 Florida                    Current           30

                 Florida                    Current           30

                 Florida                    Current           30

                 Florida                    Current           30

                 Florida                    Current           30

  **2020**       Mid-Atlantic               Wind              150

                 Mid-Atlantic               Wind              500

                 New England                Wind              500

                 New England                Wind              500

                 New York                   Wind              1,000

                 New York                   Wind              500

                 Gulf of Mexico             Wind              150

                 Oregon                     Wave              75

                 Oregon                     Wave              75

                 Florida                    Current           30

                 Florida                    Current           30

                 Florida                    Current           30

  **2021**       Mid-Atlantic               Wind              150

                 Mid-Atlantic               Wind              500

                 Southeast                  Wind              150

                 Southeast                  Wind              1,000

                 California                 Wind              1,000

  **2021         California                 Wind              500
  (cont.)**                                                   
  ----------------------------------------------------------------------------

+---------+-------------------------+----------------+---------------+
| **Yea   | **Location**            | **Type**       | **Capacity**  |
| r\*\*** |                         |                |               |
+=========+=========================+================+===============+
| *       | California              | Wind           | 500           |
| *2021** |                         |                |               |
|         |                         |                |               |
| **(c    |                         |                |               |
| ont.)** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | California              | Wind           | 500           |
+---------+-------------------------+----------------+---------------+
|         | Washington              | Wave           | 75            |
+---------+-------------------------+----------------+---------------+
|         | Oregon                  | Wave           | 75            |
+---------+-------------------------+----------------+---------------+
|         | California              | Wave           | 75            |
+---------+-------------------------+----------------+---------------+
|         | Florida                 | Current        | 30            |
+---------+-------------------------+----------------+---------------+
|         | Florida                 | Current        | 30            |
+---------+-------------------------+----------------+---------------+
| *       | Mid-Atlantic            | Wind           | 500           |
| *2022** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | New England             | Wind           | 500           |
+---------+-------------------------+----------------+---------------+
|         | New England             | Wind           | 150           |
+---------+-------------------------+----------------+---------------+
|         | New York                | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
|         | Florida                 | Current        | 30            |
+---------+-------------------------+----------------+---------------+
|         | Florida                 | Current        | 30            |
+---------+-------------------------+----------------+---------------+
|         | Florida                 | Current        | 30            |
+---------+-------------------------+----------------+---------------+
| *       | New England             | Wind           | 1,000         |
| *2023** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | Gulf of Mexico          | Wind           | 500           |
+---------+-------------------------+----------------+---------------+
|         | Gulf of Mexico          | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
| *       | New England             | Wind           | 1,000         |
| *2024** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | New England             | Wind           | 500           |
+---------+-------------------------+----------------+---------------+
|         | Mid-Atlantic            | Wind           | 500           |
+---------+-------------------------+----------------+---------------+
| *       | Mid-Atlantic            | Wind           | 500           |
| *2025** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | Mid-Atlantic            | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
|         | California              | Wind           | 500           |
+---------+-------------------------+----------------+---------------+
| *       | California              | Wind           | 1,000         |
| *2026** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | California              | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
|         | California              | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
| *       | Mid-Atlantic            | Wind           | 1,000         |
| *2027** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | Southeast               | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
| *       | Florida                 | Current        | 60            |
| *2027** |                         |                |               |
+---------+-------------------------+----------------+---------------+
| *       | Gulf of Mexico          | Wind           | 1,000         |
| *2028** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | California              | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
|         | California              | Wave           | 150           |
+---------+-------------------------+----------------+---------------+
| *       | New England             | Wind           | 1,000         |
| *2029** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | New York                | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
|         | Florida                 | Current        | 60            |
+---------+-------------------------+----------------+---------------+
| *       | Mid-Atlantic            | Wind           | 1,000         |
| *2030** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | Southeast               | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
|         | Florida                 | Current        | 60            |
+---------+-------------------------+----------------+---------------+
| *       | Gulf of Mexico          | Wind           | 1,000         |
| *2031** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | California              | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
|         | Oregon                  | Wave           | 150           |
+---------+-------------------------+----------------+---------------+
| *       | Oregon                  | Wind           | 1,000         |
| *2032** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | Washington              | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
|         | Florida                 | Current        | 60            |
+---------+-------------------------+----------------+---------------+
| *       | New England             | Wind           | 1,000         |
| *2033** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | New York                | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
|         | Florida                 | Current        | 60            |
+---------+-------------------------+----------------+---------------+
| *       | Mid-Atlantic            | Wind           | 1,000         |
| *2034** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | Southeast               | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
|         | California              | Wave           | 150           |
+---------+-------------------------+----------------+---------------+
| *       | Gulf of Mexico          | Wind           | 1,000         |
| *2035** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | California              | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
|         | California              | Wind           | 1,000         |
+---------+-------------------------+----------------+---------------+
| *       | California              | Wind           | 1,000         |
| *2036** |                         |                |               |
+---------+-------------------------+----------------+---------------+
|         | California              | Wind           | 500           |
+---------+-------------------------+----------------+---------------+
|         | California              | Wind           | 500           |
+---------+-------------------------+----------------+---------------+

\* This forecast is not indicative of any Federal government
preferences, plans, or intentions with regard to OCS alternative energy
development. While the forecast represents one possible development
path, a combination of market and government factors will ultimately
determine the type, scale, and timing of actual activity.

\*\* First year of electricity generation.

Table 2-7

Preliminary OCS Development Forecast by Project Type and Region,
2008-2036

  -------------- -------------- -------------- -------------- --------------
                 **Atlantic**   **Gulf of      **Pacific**    **TOTAL**
                                Mexico**                      

  **Wind**       48             6              16             **70**

  **Wave**       0              0              14             **14**

  **Ocean        19             0              0              **19**
  Current**                                                   

  **TOTAL**      **67**         **6**          **30**         **103**
  -------------- -------------- -------------- -------------- --------------

# 3.0 estimation of federal government costs in the baseline and alternative

This section describes the calculation of estimated costs to the Federal
government for the MMS program created by the proposed regulation, as
well as the calculation of Baseline costs.[^11] These costs are to be
compared on an annual and cumulative basis to the estimates of Federal
revenues that would be generated by the projects included in the 20-year
development forecast (2008-2027). The cost estimates are based on data
and guidance provided by MMS staff, as described below.

## 3.1 General approach

In the alternative cases, annual costs are based on MMS forecasts of the
personnel that will be required for program activities, as well as
per-project level of effort estimates for each position in the personnel
mix and for each stage of a project\'s lifecycle. The level of effort
estimates are expressed as fractions of annual full time equivalents
(FTEs). The project lifecycle stages are divided into one-year
increments. Costs are assigned to each position based on an assumed pay
grade, specified by MMS, with a fixed indirect cost rate applied to
total annual personnel costs. MMS also specified an annual cost of
living adjustment (three percent) to use in determining future year
costs.

MMS combined these data into cost templates for the periods 2008-2012
and 2013-2027. MMS\'s assumption in specifying these two periods is that
a \"learning\" process will be taking place during the first several
years of program activity, leading up to the anticipated 2012 lease
sale, and that costs will be lower beginning in 2013. The two cost
templates are presented in Tables 3-1 and 3-2. We mapped the templates
to our project forecast to generate annual cost estimates driven by the
number of projects determined to be \"in process\" in a particular year.

In addition to the level of effort templates, MMS specified additional
program and other costs (such as lease sale preparatory work) that
cannot be assigned to individual projects but that should be
incorporated into an estimate of total costs. The following additional
elements are included in the cost formulation:

-   A Program Manager (one FTE per year, grade GS-15/05) and an
    Administrative Assistant (one FTE per year, grade GS-07/05) for
    general program oversight.

> Table 3-1
>
> MMS Per-Project Cost Template, 2008-2012 (Fractions of Full-Time
> Equivalent)

<table style="width:100%;">
<colgroup>
<col style="width: 19%" />
<col style="width: 6%" />
<col style="width: 4%" />
<col style="width: 4%" />
<col style="width: 4%" />
<col style="width: 4%" />
<col style="width: 4%" />
<col style="width: 4%" />
<col style="width: 4%" />
<col style="width: 4%" />
<col style="width: 4%" />
<col style="width: 4%" />
<col style="width: 4%" />
<col style="width: 4%" />
<col style="width: 5%" />
<col style="width: 5%" />
<col style="width: 7%" />
</colgroup>
<tbody>
<tr class="odd">
<td rowspan="3"><strong>POSITION</strong></td>
<td rowspan="3"><strong>GRADE</strong></td>
<td colspan="13"><strong>YEAR</strong></td>
<td rowspan="3"><strong>TOTAL FTE<sup>2</sup></strong></td>
<td rowspan="3"><strong>TOTAL ANNUAL COST</strong></td>
</tr>
<tr class="even">
<td><strong>1</strong></td>
<td><strong>2</strong></td>
<td><strong>3</strong></td>
<td><strong>4</strong></td>
<td><strong>5</strong></td>
<td><strong>6</strong></td>
<td><strong>7</strong></td>
<td><strong>8</strong></td>
<td><strong>9</strong></td>
<td><strong>10</strong></td>
<td><strong>(11)</strong></td>
<td><strong>(12)</strong></td>
<td><strong>11-13<sup>1</sup></strong></td>
</tr>
<tr class="odd">
<td><strong>REVIEW SAP AND BEGIN INTERNAL REVIEWS</strong></td>
<td><strong>SAP DRAFT EIS</strong></td>
<td><strong>SAP FINAL EIS</strong></td>
<td><strong>DATA COLLECTION</strong></td>
<td><strong>DATA COLLECTION</strong></td>
<td><strong>DATA COLLECTION</strong></td>
<td><strong>REVIEW COP AND BEGIN INTERNAL REVIEWS</strong></td>
<td><strong>COP DRAFT EIS</strong></td>
<td><strong>COP FINAL EIS</strong></td>
<td><strong>CONSTRUCTION</strong></td>
<td><strong>CONSTRUCTION</strong></td>
<td><strong>CONSTRUCTION</strong></td>
<td><strong>OPERATIONS</strong></td>
</tr>
<tr class="even">
<td><blockquote>
<p>Biologist, Avian/Wildlife</p>
</blockquote></td>
<td>GS-13/05</td>
<td>0.104</td>
<td>0.008</td>
<td>0.008</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.044</td>
<td>0.008</td>
<td>0.008</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.187</td>
<td>$155,739</td>
</tr>
<tr class="odd">
<td><blockquote>
<p>Biologist, Fish/Benthic</p>
</blockquote></td>
<td>GS-13/05</td>
<td>0.104</td>
<td>0.008</td>
<td>0.008</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.044</td>
<td>0.008</td>
<td>0.008</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.187</td>
<td>$155,739</td>
</tr>
<tr class="even">
<td><blockquote>
<p>Archeologist</p>
</blockquote></td>
<td>GS-14/05</td>
<td>0.104</td>
<td>0.008</td>
<td>0.008</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.044</td>
<td>0.008</td>
<td>0.008</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.187</td>
<td>$184,032</td>
</tr>
<tr class="odd">
<td><blockquote>
<p>Air Quality Specialist</p>
</blockquote></td>
<td>GS-14/05</td>
<td>0.014</td>
<td>0.008</td>
<td>0.008</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.044</td>
<td>0.008</td>
<td>0.008</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.097</td>
<td>$184,032</td>
</tr>
<tr class="even">
<td><blockquote>
<p>Social Scientist/Economist</p>
</blockquote></td>
<td>GS-14/05</td>
<td>0.104</td>
<td>0.008</td>
<td>0.008</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.154</td>
<td>0.008</td>
<td>0.008</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.297</td>
<td>$184,032</td>
</tr>
<tr class="odd">
<td><blockquote>
<p>Oceanographer</p>
</blockquote></td>
<td>GS-13/05</td>
<td>0.044</td>
<td>0.008</td>
<td>0.008</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.504</td>
<td>0.008</td>
<td>0.008</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.587</td>
<td>$155,739</td>
</tr>
<tr class="even">
<td><blockquote>
<p>CZM Specialist</p>
</blockquote></td>
<td>GS-14/05</td>
<td>0.104</td>
<td>0.008</td>
<td>0.008</td>
<td> </td>
<td> </td>
<td> </td>
<td>0.044</td>
<td>0.008</td>
<td>0.008</td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td>0.180</td>
<td>$184,032</td>
</tr>
<tr class="odd">
<td><blockquote>
<p>GIS Specialist</p>
</blockquote></td>
<td>GS-12/05</td>
<td>0.004</td>
<td>0</td>
<td>0</td>
<td> </td>
<td> </td>
<td> </td>
<td>0.040</td>
<td>0.000</td>
<td>0.000</td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td>0.044</td>
<td>$130,966</td>
</tr>
<tr class="even">
<td><blockquote>
<p>Attorney</p>
</blockquote></td>
<td>GS-14/05</td>
<td>0.004</td>
<td>0.012</td>
<td>0.016</td>
<td> </td>
<td> </td>
<td> </td>
<td>0.004</td>
<td>0.012</td>
<td>0.016</td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td>0.064</td>
<td>$184,032</td>
</tr>
<tr class="odd">
<td><blockquote>
<p>Geophysicist/Geologist</p>
</blockquote></td>
<td>GS-13/05</td>
<td>0.044</td>
<td>0.008</td>
<td>0.008</td>
<td> </td>
<td> </td>
<td> </td>
<td>0.044</td>
<td>0.008</td>
<td>0.008</td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td>0.120</td>
<td>$155,739</td>
</tr>
<tr class="even">
<td><blockquote>
<p>Engineer</p>
</blockquote></td>
<td>GS-14/05</td>
<td>0.004</td>
<td>0</td>
<td>0</td>
<td> </td>
<td> </td>
<td> </td>
<td>0.004</td>
<td>0.000</td>
<td>0.000</td>
<td>0.160</td>
<td> </td>
<td> </td>
<td> </td>
<td>0.168</td>
<td>$184,032</td>
</tr>
<tr class="odd">
<td><blockquote>
<p>Multi-Disciplinary/Various</p>
</blockquote></td>
<td>GS-13/05</td>
<td>0.008</td>
<td>0.008</td>
<td>0.008</td>
<td> </td>
<td> </td>
<td> </td>
<td>0.008</td>
<td>0.008</td>
<td>0.008</td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td>0.048</td>
<td>$155,739</td>
</tr>
<tr class="even">
<td><blockquote>
<p><strong>Subtotal</strong></p>
</blockquote></td>
<td><strong> </strong></td>
<td><strong>0.642</strong></td>
<td><strong>0.084</strong></td>
<td><strong>0.088</strong></td>
<td><strong>0.006</strong></td>
<td><strong>0.006</strong></td>
<td><strong>0.006</strong></td>
<td><strong>0.978</strong></td>
<td><strong>0.084</strong></td>
<td><strong>0.088</strong></td>
<td><strong>0.166</strong></td>
<td><strong>0.006</strong></td>
<td><strong>0.006</strong></td>
<td><strong>0.006</strong></td>
<td><strong>2.166</strong></td>
<td><strong> </strong></td>
</tr>
</tbody>
</table>

Notes:

SAP = Site Assessment Plan or equivalent; COP = Construction and
Operations Plan or equivalent

1\. Since construction times vary from one to three years (depending on
project size), the start year of the operations phase varies by project.

2\. Annual MMS costs during the 20-year operations phase are assumed to
be constant. Accordingly, the total FTE calculation sums values through
the construction phase, then adds 20 times the operating phase value.

Table 3-2

> MMS Per-Project Cost Template, 2013-2027 (Fractions of Full-Time
> Equivalent)

<table>
<colgroup>
<col style="width: 20%" />
<col style="width: 6%" />
<col style="width: 5%" />
<col style="width: 5%" />
<col style="width: 5%" />
<col style="width: 5%" />
<col style="width: 5%" />
<col style="width: 5%" />
<col style="width: 5%" />
<col style="width: 5%" />
<col style="width: 5%" />
<col style="width: 5%" />
<col style="width: 5%" />
<col style="width: 5%" />
<col style="width: 9%" />
</colgroup>
<tbody>
<tr class="odd">
<td rowspan="3"><strong>POSITION</strong></td>
<td rowspan="3"><strong>GRADE</strong></td>
<td colspan="11"><strong>YEAR</strong></td>
<td rowspan="3"><strong>TOTAL FTE<sup>2</sup></strong></td>
<td rowspan="3"><strong>TOTAL ANNUAL SUPPORT COST</strong></td>
</tr>
<tr class="even">
<td><strong>1</strong></td>
<td><strong>2</strong></td>
<td><strong>3</strong></td>
<td><strong>4</strong></td>
<td><strong>5</strong></td>
<td><strong>6</strong></td>
<td><strong>7</strong></td>
<td><strong>8</strong></td>
<td><strong>(9)</strong></td>
<td><strong>(10)</strong></td>
<td><strong>9 to 11<sup>1</sup></strong></td>
</tr>
<tr class="odd">
<td><strong>SAP DRAFT EIS</strong></td>
<td><strong>SAP FINAL EIS</strong></td>
<td><strong>DATA COLLECTION</strong></td>
<td><strong>DATA COLLECTION</strong></td>
<td><strong>DATA COLLECTION</strong></td>
<td><strong>COP DRAFT EIS</strong></td>
<td><strong>COP FINAL EIS</strong></td>
<td><strong>CONSTRUCTION</strong></td>
<td><strong>CONSTRUCTION</strong></td>
<td><strong>CONSTRUCTION</strong></td>
<td><strong>OPERATIONS</strong></td>
</tr>
<tr class="even">
<td><blockquote>
<p>Biologist, Avian/Wildlife</p>
</blockquote></td>
<td>GS-13/05</td>
<td>0.026</td>
<td>0.004</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.049</td>
<td>0.009</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.113</td>
<td>$155,739</td>
</tr>
<tr class="odd">
<td><blockquote>
<p>Biologist, Fish/Benthic</p>
</blockquote></td>
<td>GS-13/05</td>
<td>0.026</td>
<td>0.004</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.049</td>
<td>0.009</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.113</td>
<td>$155,739</td>
</tr>
<tr class="even">
<td><blockquote>
<p>Archeologist</p>
</blockquote></td>
<td>GS-14/05</td>
<td>0.026</td>
<td>0.004</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.049</td>
<td>0.009</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.113</td>
<td>$184,032</td>
</tr>
<tr class="odd">
<td><blockquote>
<p>Air Quality Specialist</p>
</blockquote></td>
<td>GS-14/05</td>
<td>0.01</td>
<td>0.004</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.029</td>
<td>0.009</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.077</td>
<td>$184,032</td>
</tr>
<tr class="even">
<td><blockquote>
<p>Social Scientist/Economist</p>
</blockquote></td>
<td>GS-14/05</td>
<td>0.01</td>
<td>0.004</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.029</td>
<td>0.009</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.077</td>
<td>$184,032</td>
</tr>
<tr class="odd">
<td><blockquote>
<p>Oceanographer</p>
</blockquote></td>
<td>GS-13/05</td>
<td>0.01</td>
<td>0.004</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.029</td>
<td>0.009</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.001</td>
<td>0.077</td>
<td>$155,739</td>
</tr>
<tr class="even">
<td><blockquote>
<p>CZM Specialist</p>
</blockquote></td>
<td>GS-14/05</td>
<td>0.01</td>
<td>0.004</td>
<td> </td>
<td> </td>
<td> </td>
<td>0.028</td>
<td>0.008</td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td>0.050</td>
<td>$184,032</td>
</tr>
<tr class="odd">
<td><blockquote>
<p>GIS Specialist</p>
</blockquote></td>
<td>GS-12/05</td>
<td>0.004</td>
<td>0</td>
<td> </td>
<td> </td>
<td> </td>
<td>0.004</td>
<td>0.000</td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td>0.008</td>
<td>$130,966</td>
</tr>
<tr class="even">
<td><blockquote>
<p>Attorney</p>
</blockquote></td>
<td>GS-14/05</td>
<td>0.008</td>
<td>0.008</td>
<td> </td>
<td> </td>
<td> </td>
<td>0.008</td>
<td>0.008</td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td>0.032</td>
<td>$184,032</td>
</tr>
<tr class="odd">
<td><blockquote>
<p>Geophysicist/Geologist</p>
</blockquote></td>
<td>GS-13/05</td>
<td>0.01</td>
<td>0.004</td>
<td> </td>
<td> </td>
<td> </td>
<td>0.028</td>
<td>0.008</td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td>0.050</td>
<td>$155,739</td>
</tr>
<tr class="even">
<td><blockquote>
<p>Engineer</p>
</blockquote></td>
<td>GS-14/05</td>
<td>0.004</td>
<td>0</td>
<td> </td>
<td> </td>
<td> </td>
<td>0.004</td>
<td>0.000</td>
<td>0.160</td>
<td> </td>
<td> </td>
<td> </td>
<td>0.808</td>
<td>$184,032</td>
</tr>
<tr class="odd">
<td><blockquote>
<p>Multi-Disciplinary/Various</p>
</blockquote></td>
<td>GS-13/05</td>
<td>0.01</td>
<td>0.004</td>
<td> </td>
<td> </td>
<td> </td>
<td>0.008</td>
<td>0.008</td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td>0.030</td>
<td>$155,739</td>
</tr>
<tr class="even">
<td><blockquote>
<p><strong>Subtotal</strong></p>
</blockquote></td>
<td><strong> </strong></td>
<td><strong>0.154</strong></td>
<td><strong>0.044</strong></td>
<td><strong>0.006</strong></td>
<td><strong>0.006</strong></td>
<td><strong>0.006</strong></td>
<td><strong>0.314</strong></td>
<td><strong>0.086</strong></td>
<td><strong>0.166</strong></td>
<td><strong>0.006</strong></td>
<td><strong>0.006</strong></td>
<td><strong>0.006</strong></td>
<td><strong>1.548</strong></td>
<td><strong> </strong></td>
</tr>
</tbody>
</table>

Notes:

SAP = Site Assessment Plan or equivalent; COP = Construction and
Operations Plan or equivalent

1\. Since construction times vary from one to three years (depending on
project size), the start year of the operations phase varies by project.

2\. Annual MMS costs during the 20-year operations phase are assumed to
be constant. Accordingly, the total FTE calculation sums values through
the construction phase, then adds 20 times the operating phase value.

-   A Project Manager/NEPA Coordinator (one FTE, grade GS-14/05) for
    each project that has a Site Assessment Plan or Construction and
    Operations Plan under review.

-   An Inspector/Engineering Tech function (grade GS-11/05) at 0.004 FTE
    for each operating plan that is approved in a given year.

-   A total of \$3 million per year for environmental assessments.

In the Baseline case, Federal government costs are limited to the cost
of one Corps FTE per new wind energy project application. We assume no
net cost for FERC activities in the Baseline case, since that agency
offsets its costs through the collection of various administrative fees.
For each position in the personnel mix, the product of the annual cost
per person, the number of FTEs per project, and the number of projects
in a given year serves as an estimate of the annual programmatic cost,
with adjustments to account for general costs of holding the lease sale
in the scenario and of program development, especially in the early
years. The sum of these programmatic costs across all positions in the
personnel mix, along with \$3 million per year to approximate the costs
of necessary environmental studies as the program develops and expands,
is the estimate of the Federal government\'s total cost for that year.
During the period 2008-2012, we also make the simplifying assumption
that program development activities will remain constant and that
variations in annual costs will reflect only the differing numbers of
projects that are in process during a particular year. Finally, for the
purpose of this analysis, MMS assumes that project developers will bear
the costs of the necessary environmental impact statements (EIS), with
the exception of the EIS for the single lease sale assumed to occur in
2012, and that MMS will review each EIS. We do not account explicitly
for a developer\'s EIS preparation costs in our cash flow model. Project
developers also will pay for some independent inspections, which will be
reviewed by MMS. MMS will also conduct scheduled or random inspections
or will hire third-party inspectors to do so.[^12]

## 3.2 Discussion

For this analysis, personnel compensation plus indirect cost and program
support cost add-ons are used to estimate an all-inclusive measure of
future MMS programmatic costs. To the extent there are relevant program
costs that are not incorporated into the indirect and program support
factors, our estimate would understate the total program costs. In
addition, we note the following factors that may result in either an
over- or under-statement of future costs.

1.  Although we estimate anticipated non-tax Federal government revenues
    associated with the development of OCS alternative energy projects,
    we estimate only those Federal government costs incurred by MMS, not
    those that will be incurred by other Federal agencies (e.g., the US
    Fish and Wildlife Service) responsible for additional reviews of
    project planning and development activities. Exclusion of these
    costs results in an understatement of estimated total Federal
    government costs.

2.  The level of effort associated with the operational phase may be
    highly site-specific and subject to considerable variation (e.g.,
    monitoring requirements at one site might be suspended based on the
    results of confirmatory monitoring conducted during the first years
    of operation, whereas continuous monitoring (and oversight) might be
    required for the life of another project).

3.  Institutional learning could occur at a rate that differs from that
    assumed by MMS and could continue to occur throughout the period of
    analysis. A more pronounced learning effect would result in
    estimated total program costs lower than those we have calculated.

4.  Some or all of the program review and management function could
    eventually move out of the MMS headquarters offices and into
    regional offices, where costs may be lower, on average. If this were
    to happen as the program matures, our estimate would likely be an
    overstatement of total program costs.

5.  Some of the attorney cost associated with program activities will
    likely be incurred by the Office of the Solicitor within the
    Department of the Interior, rather than by MMS directly. This factor
    also may cause our estimate to overstate total MMS costs.

6.  Initially, the cost of ensuring that all revenues from OCS
    alternative energy and alternate use leases and grants are
    accurately collected, and disbursed to appropriate recipients in a
    timely manner, would be covered by funding presently utilized for
    discretionary activities.  Over time, additional funding would be
    required for MMS to manage alternative energy and alternate use
    revenues.  In addition, if MMS were to base operating fees on actual
    generation of electricity, rather than on generation capacity, it
    would have to collect and examine contracts and implement an audit
    program. These costs are not accounted for in the analysis, and
    their exclusion results in a potential understatement of total
    program costs.

7.  No costs are included for the management review and decision
    process. This should result in only a minor understatement of
    program costs.

# 4.0 estimation of transfer payments to the u.S. treasury resulting from projects included in the alternative energy development forecast

The Excel cash flow model used to estimate payments to the Federal
government incorporates both project-specific and general assumptions.
The project-specific assumptions include technical details (e.g., size,
capacity factor, capital and O&M costs, years to construct) as well as
the initial value of financial incentives (i.e., the production tax
credit (PTC) and renewable energy certificates (RECs), as appropriate)
for each of the projects in the development forecast. General
assumptions address factors such as regional electricity price forecasts
and construction financing terms. In addition, the model incorporates
financial assurance requirements as specified in the rule. The cash flow
statement covers a project\'s lifetime, from pre-development through a
20-year period of electricity generation to decommissioning. Thus, the
last project in the forecast begins operation in 2027 and operates
through 2046. However for the purposes of this analysis, we only report
the revenues and costs that are realized during the period 2008-2027.

In general, assumptions incorporated into the model reflect the
electricity and alternative energy markets and policy landscapes as they
existed at the time of the analysis. With one exception, we did not
assume any market or policy changes that might provide an advantage or
disadvantage to OCS alternative energy projects during the period of
analysis. Furthermore, we assumed that any factor in place at the time
of the analysis would remain in place throughout the period of analysis.
The exception to this rule was an assumption that the Federal PTC would
become available to wave and ocean current energy projects, in addition
to wind energy projects, prior to the operational phases of the first
projects of these kinds.[^13] Title 26 -- Internal Revenue Code,
Subtitle A, Chapter 1, Subchapter A, Part IV, Subpart D, Sec. 45(a) and
45(d)(1), specifies that wind energy generators may claim the credit for
a qualified facility during the 10 year period beginning on the date the
facility was originally placed in service. The credit amount for 2007
was \$0.02 per kilowatt-hour, according to the Internal Revenue
Service's Internal Revenue Bulletin 2007-21, Notice 2007-40, published
on May 21, 2007.

As part of our examination of the cash flow for projects in the
preliminary development forecast (given model assumptions), we applied
specific, internal rate of return (IRR)-based criteria (as specified by
MMS) for the evaluation of economic viability. Below an IRR of five
percent, we assumed that the project might be proposed but would not
formally enter the pre-development phase, and thus would result in
minimal Federal costs and no Federal revenues. For projects that
exhibited an IRR equal to or greater than five percent but less than 11
percent, we assumed that some pre-development activity would occur but
that construction and operation of the project would not. In these
cases, we calculated and recorded Federal revenues and costs associated
only with the predevelopment period. We calculated and recorded all
Federal revenues and costs for the projects with an IRR greater than or
equal to 11 percent. Table 4-1 presents the effect of applying our
economic viability screen to the projects in each of the three payment
cases. Tables 4-2 through 4-4 present the screening results for wind (by
size category), wave, and ocean current energy projects, respectively.
Notable results from this analysis include:

-   The initial development forecast comprised 76 projects that would
    begin construction before 2027, the last year of the period of
    analysis. We evaluated the financial viability of each project and
    found that 58 of the 76 might be considered viable under the payment
    requirements of the Baseline (no payments), Low and Intermediate
    cases. In fact, the categorization of wind energy projects by IRR
    does not vary between payment cases, with the exception of three 500
    MW projects that drop below an 11 percent IRR in the High case.[^14]
    This analysis implies that the magnitude of MMS payments under the
    assumed cases should not have a significant influence on decisions
    to invest in lease development on the OCS.

-   For wind energy projects, in all cases, half of the 150 MW projects
    have an IRR greater than or equal to 11 percent, whereas a
    significant majority of the larger projects clear this rate.

-   Of the nine wave energy projects included in our 2008 to 2027
    forecast, none clear the lower hurdle rates due to their location
    exclusively in the Pacific region, particularly the Pacific
    Northwest, which in our model is a low electricity price market
    (driven by the presence of large, lower cost onshore hydroelectric
    resources). Wave energy projects developed over the next 20 years
    might be more economically viable in nearer-shore environments that
    are subject to State rather than MMS jurisdiction.

-   In contrast, all of the 15 ocean current projects included in the
    2008 to 2027 forecast have IRRs greater than or equal to 11 percent,
    primarily because of their relatively high capacity factors (80
    percent compared to 38 percent for wind and 35 percent for wave).

-   For the Intermediate case, we found that the number of viable
    projects modeled in the development forecast would drop from 58 to
    43 without revenue from the sale of RECs. It is reasonable to
    assume, therefore, that the establishment and maintenance of
    renewable portfolio standards by coastal states would be essential
    to the economic success of many OCS projects. Section 5.0 includes
    more discussion on the sensitivity of project finances to REC
    revenue, electricity prices, and other assumptions for financing,
    generation and costs.

Table 4-5 presents the total installed electricity capacity by
technology for those projects that are forecast to be constructed before
2028. Installed capacity figures estimated for each technology
correspond to the number of projects determined to be financially
viable; that is, those projects with an IRR greater than or equal to 11
percent. For example, as shown in Table 4-2, the total estimated wind
project installed capacity of 25,200 MW in the Baseline, Low, and
Intermediate cases includes eight projects with nameplate capacities of
150 MW, 22 projects with nameplate capacities of 500 MW, and 13 projects
with nameplate capacities of 1,000 MW. For project-specific information
on electricity generation and financial performance for each payment
case, see Appendix B. []{.mark}

We also analyzed the effect that elimination of the present Federal PTC
could have on the viability of the wind, wave and current projects
evaluated. We estimated that if the PTC were not extended beyond its
current expiration date of December 31, 2008, only 33 of the 76 projects
might have IRRs of greater than or equal to 11 percent, regardless of
the payment case analyzed. The difference in the number of projects
constructed, 25 fewer than the 58 viable for the Baseline, Low and
Intermediate cases, may be less if a change to economic conditions
creates a benefit approximately equivalent to the PTC. We concluded that
project viability is more sensitive to the availability of the PTC
benefit than REC benefits, or any of the fiscal requirements assumed in
the payment cases. Section 6.0 provides results from this part of the
analysis.

The MMS further reviewed 12 of the 25 projects that might not be
constructed without the PTC, to discern how much the MMS payments could
detract from the value of the PTC. Specifically, the value of MMS
payments relative to the PTC value was calculated as a percentage: 1)
for the 10 years that the PTC would be in effect for each project, and
2) over the life of each project. Lease interests would discount the
values at private rates and the government would discount with social
rates. To simplify presentation of the results here, percentages were
calculated with undiscounted nominal dollar values. Results show that
the value of MMS payments relative to the PTC value for the 10 years
that the PTC would be in effect for each project ranged from of 4.5 to
6.5 percent. Percentages calculated using the total of all payments made
to MMS over the life of the project, divided by the total value of the
PTCs over the 10 years following the date that a project is placed in
service, ranged from about 11.0 percent to 14.5 percent. The second set
of percentages is higher than the first set because payments made before
and after the 10 year PTC period are considered. The MMS recognizes that
the alternative energy program payment requirements would effectively
lower the value of the PTC. However, the payment cases analyzed would
not reduce the value of the PTC by a significant amount. Of greater
importance, this analysis seems to imply that the elimination of the
requirement to make payments to MMS might not increase the rate of
alternative energy development on the OCS.

As a final step before calculating annual and cumulative Federal
revenues and costs, it would also be appropriate to assume that some
percentage of \"viable\" projects would not reach the construction and
operations stage due to reasons other than projected economic
performance (e.g., MMS rejection of an application on technical
grounds). In our analysis, we did not further reduce the number of
projects on this basis due to our inability to define a credible rule
for selecting the projects that would not proceed.

We did not complete cash flow analyses for, and thus did not apply the
IRR test to, projects that are assumed to begin operations after 2027
(but that result in Federal revenues and costs during a pre-2028
development period). Rather, we simply assumed that the projects
assigned to this period (the 27 that increase the preliminary forecast
from 76 to 103 projects) would proceed through the pre-operational
period. Since Federal revenues and costs associated with the operational
phase of these projects would not figure into our results (as they would
occur after 2027), it is unnecessary to undertake a complete cash flow
analysis. In making this decision, we also recognized that the already
considerable uncertainty associated with key model inputs, such as
electricity prices, would border on pure speculation if we were to try
to estimate values more than 20 years into the future.

Finally, we note that the treatment of Federal taxes, though not
recorded as a source of government revenue in this analysis, is an
important factor in the cash flow model\'s assessment of project
viability.[^15] In our model, we assume that renewable energy project
developers would be able to apply net operating losses from a wind,
wave, or ocean current energy project against income from other sources.
We apply the reduced tax obligation on this income as a benefit to the
renewable energy project. This accounting method is not intended to show
how a taxpayer would complete a tax return; we apply it for analytical
purposes only.

Table 4-6 lists and describes key cash flow model inputs. (Appendix A
provides a more detailed description of the cash flow model.) Table 4-7
presents the terms of the three payment cases (Low, Intermediate, and
High), as defined by MMS, that the cash flow model simulates. In each of
the cases, rental payments would be required prior to the construction
and operation of a generation facility. In the Intermediate and High
cases, MMS would charge an annual operating fee during the construction
and operations phases. In the Low case, a rental payment would
substitute for an operating fee during construction and operations.

Table 4-1

Results of Economic Viability Screening for Projects Operational by 2027

  ----------------- ----------------- ------------------ ------------------
  **Payment Case**  **Number of                          
                    Projects**                           

                    IRR \< 5 %        5 %                11 %
                                      [\<]{.underline}   [\<]{.underline}
                                      IRR \< 11 %        IRR

  Baseline          13                5                  58

  Low               13                5                  58

  Intermediate      13                5                  58

  High              13                8                  55
  ----------------- ----------------- ------------------ ------------------

Table 4-2

Results of Economic Viability Screening for Wind Projects Operational by
2027

  -------------- ------------ --------------- ------------------ ------------------
  **Payment      **Rated      **Number of                        
  Case**         Plant        Projects**                         
                 Capacity                                        
                 (MW)**                                          

                              IRR \< 5 %      5 %                11 %
                                              [\<]{.underline}   [\<]{.underline}
                                              IRR \< 11 %        IRR

  Baseline       150          4               4                  8

                 500          0               1                  22

                 1,000        0               0                  13

                 **Total**    **4**           **5**              **43**

  Low            150          4               4                  8

                 500          0               1                  22

                 1,000        0               0                  13

                 **Total**    **4**           **5**              **43**

  Intermediate   150          4               4                  8

                 500          0               1                  22

                 1,000        0               0                  13

                 **Total**    **4**           **5**              **43**

  High           150          4               4                  8

                 500          0               4                  19

                 1,000        0               0                  13

                 **Total**    **4**           **8**              **40**
  -------------- ------------ --------------- ------------------ ------------------

Table 4-3

Results of Economic Viability Screening for Wave Projects Operational by
2027

  ----------------- ----------------- ------------------ ------------------
  **Payment Case**  **Number of                          
                    Projects**                           

                    IRR \< 5 %        5 %                11 %
                                      [\<]{.underline}   [\<]{.underline}
                                      IRR \< 11 %        IRR

  Baseline          9                 0                  0

  Low               9                 0                  0

  Intermediate      9                 0                  0

  High              9                 0                  0
  ----------------- ----------------- ------------------ ------------------

Table 4-4

Results of Economic Viability Screening for Current Projects Operational
by 2027

  ----------------- ----------------- ------------------ ------------------
  **Payment Case**  **Number of                          
                    Projects**                           

                    IRR \< 5 %        5 %                11 %
                                      [\<]{.underline}   [\<]{.underline}
                                      IRR \< 11 %        IRR

  Baseline          0                 0                  15

  Low               0                 0                  15

  Intermediate      0                 0                  15

  High              0                 0                  15
  ----------------- ----------------- ------------------ ------------------

Table 4-5

Installed Capacity of Constructed Wind, Wave, and Current Projects
Operational by 2027

  ----------------------- ------------------------ -----------------------
  **Payment Case**        **Technology**           **Installed Capacity of
                                                   Constructed Projects
                                                   (MW)**

  Baseline                Wind                     25,200

                          Wave                     0

                          Current                  480

                          **Total**                **25,680**

  Low                     Wind                     25,200

                          Wave                     0

                          Current                  480

                          **Total**                **25,680**

  Intermediate            Wind                     25,200

                          Wave                     0

                          Current                  480

                          **Total**                **25,680**

  High                    Wind                     23,700

                          Wave                     0

                          Current                  480

                          **Total**                **24,180**
  ----------------------- ------------------------ -----------------------

Table 4-6

Description of Key Cash Flow Model Inputs

  ------------------------------------------------------------------------------------------------------------------
  **Category**      **Input**            **Value**            **Description/Rationale**
  ----------------- -------------------- -------------------- ------------------------------------------------------
  Project Finance   Inflation rate       1.9 %                Based on the GDP Chain-Type Index in Table 19 of the
                                                              EIA Annual Energy Outlook
                                                              (<http://www.eia.doe.gov/oiaf/aeo/aeoref_tab.html>,
                                                              accessed on June 7, 2007) and corroborated by the
                                                              Congressional Budget Office\'s Economic Projections
                                                              for the Calendar Years between 2007 and 2017
                                                              (<http://www.cbo.gov/budget/econproj.pdf>, accessed on
                                                              June 6, 2007). The inflation rate is assumed to remain
                                                              constant through the period of analysis.

                    Debt financing rate  6.86 %               Based on direction provided by MMS, set at 1.5% above
                                                              the 3-month LIBOR rate (as reported at
                                                              <http://www.bloomberg.com/markets/rates/index.html>,
                                                              accessed most recently on July 9, 2007).

                    Construction loan    5.0%                 While construction is occurring, a portion of
                    rate                                      construction loan funds are available for
                                                              re-investment (i.e., when the loan is first secured,
                                                              only a portion of the funds are accounted for in
                                                              construction costs). Therefore, the construction loan
                                                              rate is the debt financing rate adjusted downward to
                                                              reflect a reasonable return on reinvested funds. At
                                                              MMS\'s direction, we set this rate at 5.0%.

                    Initial debt         70 %                 We assume a current debt:equity ratio of 70:30,
                    fraction                                  reflecting the above average risk associated with
                                                              offshore alternative energy projects. We assume a
                                                              shift over time toward a more balanced split, similar
                                                              to that associated with conventional power plant
                                                              projects. Specifically, we assume a 63:37 ratio
                                                              beginning in 2012, a 56:44 ratio beginning in 2017,
                                                              and a 50:50 ratio beginning in 2022.

                    Debt distribution    Varies over time     Our analysis assumes that all non-construction related
                                                              costs incurred prior to the revenue generating phase
                                                              are funded using term debt rather than equity. These
                                                              additional costs include any financial assurance
                                                              payments, as well as any fee payments to MMS.
                                                              Consequently, debt will make up a larger fraction of
                                                              the total project funds than indicated by the
                                                              debt:equity ratio for that year.

  Project Revenues  Electricity prices   Varies by location   Average of on- and off-peak spot prices as reported in
                                                              the FERC 2006 State of the Markets Report
                                                              (<http://www.ferc.gov/oversight>, accessed on June 6,
                                                              2007). Prices in future years are estimated using a
                                                              multiplier derived from a combination of inflation and
                                                              a \"price growth factor\" (see 2007 EIA AEO Reference
                                                              Case Table 8, \"Prices by Service
                                                              Category/Generation,\" available at
                                                              <http://www.eia.doe.gov/oiaf/aeo/index.html>).

                    Renewable energy     Varies by location   We calculated REC sales revenues for those projects
                    certificate (REC)                         associated with States or regions where a Renewable
                    value                                     Portfolio Standard (RPS) has been enacted and has
                                                              created or will create a market for RECs. We further
                                                              assume that each RPS, and the ability to realize REC
                                                              sales revenues, will remain in place throughout the
                                                              period of analysis. Current RPS information comes from
                                                              the Database of State Incentives for Renewable Energy
                                                              (<http://www.dsireusa.org/>). Limited data are
                                                              available to describe REC prices in those areas where
                                                              markets exist. We relied upon a data summary found in
                                                              the *Annual Report on U.S. Wind Power Installation,
                                                              Cost, and Performance Trends: 2006*
                                                              (<http://www.nrel.gov/docs/fy07osti/41435.pdf>,
                                                              accessed on April 15, 2007) to determine the
                                                              appropriate order of magnitude for REC prices in those
                                                              regions where data exist (New England, Mid-Atlantic,
                                                              Texas). Lacking additional information, we assumed
                                                              that similar prices will apply to sales from projects
                                                              associated with the California, Oregon, and Washington
                                                              markets.

  Project           Capacity factor      Varies by technology We used default capacity factors of 38 percent, 35
  Characteristics                                             percent, and 80 percent for wind, wave, and ocean
  and Costs                                                   current projects, respectively.

                    Area                 Capacity-dependent   As a rule of thumb we assumed one square mile for each
                                                              25 MW of capacity. MMS leases are measured in nine
                                                              square mile blocks (i.e., with a presumed capacity of
                                                              225 MW). Therefore, the areal extent (in lease blocks)
                                                              of a project is determined by dividing planned
                                                              capacity by 225. Since MMS only leases full blocks,
                                                              all results are rounded up (e.g., a 500 MW project
                                                              would be required to lease three full blocks, with an
                                                              area of 27 square miles).

  Project           Construction         1, 2, or 3 years     Construction is assumed to occur in one year for
  Characteristics   duration                                  projects with rated capacities less than or equal to
  and Costs (cont.)                                           150 MW, in two years for projects with rated
                                                              capacities greater than 150 MW but less than or equal
                                                              to 500 MW, and in three years for projects with rated
                                                              capacities greater than 500 MW.

                    Installed capital    Varies by technology For wind projects, the installed capital costs (\$/kW)
                    cost                                      are assumed to vary by project size according to the
                                                              schedule presented in Section 2. Estimated wave and
                                                              ocean current capital costs are as described in
                                                              Section 2. For each technology, learning is assumed to
                                                              result in cost reductions over time.

                    Operations and       Varies by technology For wind projects, a base O&M cost is from the
                    maintenance (O&M)                         estimate provided in ATM (2007), the recent Rhode
                    costs                                     Island offshore wind energy siting study. The O&M
                                                              estimate for wave energy is taken from Previsic
                                                              (2004b). Lacking technology-specific information, O&M
                                                              for ocean current energy is assumed to be the same as
                                                              wave energy. In all three cases, O&M costs are assumed
                                                              to decrease over time, due to learning, at the same
                                                              rate at which capital costs decline.

  Financial         Preliminary site     \$5,000/year         Proposed regulation §285.515(a) requires that a bond
  Assurance         assessment-related                        of at least \$100,000 be provided to ensure the
  Requirements      decommissioning bond                      availability of funds for decommissioning of any site
                    of \$100,000                              assessment-related equipment. The \$5,000 payment (an
                                                              MMS estimate of the annual cost of obtaining the
                                                              required bond) is levied prior to the start of the
                                                              electricity generation phase.

                    Operating term       Deposit calculated   The value of the required post-operations
                    decommissioning      based on installed   decommissioning deposit is calculated as seven percent
                    account              capital cost         of total capital costs inflated to the year after the
                                                              last year of operations and then discounted at 4.75
                                                              percent (under the assumption that the deposit will
                                                              earn interest at this rate during the operational
                                                              period). Proposed regulation §285.527 would allow this
                                                              type of financial assurance.

                    Project easement     \$15,000/year        Proposed regulation §285.520(a) requires that a bond
                    decommissioning bond                      of at least \$300,000 be provided to ensure the
                    of \$300,000                              availability of funds for decommissioning of cables
                                                              and other infrastructure within the OCS easement. The
                                                              \$15,000 payment (an MMS estimate of the annual cost
                                                              of obtaining the required bond) is levied throughout
                                                              the operating period.
  ------------------------------------------------------------------------------------------------------------------

Table 4-7

Low, Intermediate, and High Payment Cases

+---------------+-----------------+-----------------+-----------------+
| **Payment     | **Fiscal        |                 |                 |
| type**        | Terms**         |                 |                 |
+===============+=================+=================+=================+
|               | [L              | [Intermedia     | [Hi             |
|               | ow]{.underline} | te]{.underline} | gh]{.underline} |
+---------------+-----------------+-----------------+-----------------+
| Minimum bid   | \$0.25/acre     | Same as Low     | Same as Low     |
| (competitive) |                 | case            | case            |
| or            |                 |                 |                 |
| acquisition   |                 |                 |                 |
| fee           |                 |                 |                 |
| (non          |                 |                 |                 |
| -competitive) |                 |                 |                 |
+---------------+-----------------+-----------------+-----------------+
| Lease rental  | \$3/acre/year   | \$3/acre/year   | \$3/acre/year   |
|               | for the         | for the         | for the         |
|               | duration of the | preliminary and | preliminary     |
|               | lease           | site assessment | term and the    |
|               |                 | terms           | first two years |
|               |                 |                 | of the site     |
|               |                 |                 | assessment      |
|               |                 |                 | term; increases |
|               |                 |                 | to \$4/acre in  |
|               |                 |                 | site assessment |
|               |                 |                 | years 3-4 and   |
|               |                 |                 | to \$5/acre in  |
|               |                 |                 | site assessment |
|               |                 |                 | year 5 and      |
|               |                 |                 | beyond          |
+---------------+-----------------+-----------------+-----------------+
| Easement      | \$5/acre/year   | Same as Low     | Same as Low     |
| rental        |                 | case            | case            |
+---------------+-----------------+-----------------+-----------------+
| Operating fee | None            | Installed       | > Same as       |
|               |                 | capacity x 8760 | > Intermediate  |
|               |                 | hours per year  | > through the   |
|               |                 | x capacity      | > first two     |
|               |                 | factor x power  | > years with    |
|               |                 | price x fee     | > subsequent    |
|               |                 | rate, as        | > fee rates of: |
|               |                 | follows:        |                 |
|               |                 |                 | -   3% during   |
|               |                 | -   1 % during  |     operational |
|               |                 |     first two   |     years 3-8   |
|               |                 |     years\*     |                 |
|               |                 |                 | -   5% during   |
|               |                 | -   2% during   |     operational |
|               |                 |     remaining   |     years 9-15  |
|               |                 |     years of    |                 |
|               |                 |     the         | -   10% during  |
|               |                 |     operational |     operational |
|               |                 |     term        |     years 16    |
|               |                 |                 |     and beyond  |
+---------------+-----------------+-----------------+-----------------+
| Additional    | None            | None            | 10% of          |
| operating fee |                 |                 | REC-derived     |
|               |                 |                 | income          |
|               |                 |                 | beginning in    |
|               |                 |                 | operational     |
|               |                 |                 | year 16         |
+---------------+-----------------+-----------------+-----------------+
| \* Note: A    |                 |                 |                 |
| fee rate of 1 |                 |                 |                 |
| percent is    |                 |                 |                 |
| used for the  |                 |                 |                 |
| first two     |                 |                 |                 |
| years of the  |                 |                 |                 |
| operational   |                 |                 |                 |
| term, the     |                 |                 |                 |
| time period   |                 |                 |                 |
| in which      |                 |                 |                 |
| construction  |                 |                 |                 |
| would occur.  |                 |                 |                 |
| Construction  |                 |                 |                 |
| time          |                 |                 |                 |
| assumptions   |                 |                 |                 |
| for projects  |                 |                 |                 |
| evaluated in  |                 |                 |                 |
| this analysis |                 |                 |                 |
| vary          |                 |                 |                 |
| depending on  |                 |                 |                 |
| project type  |                 |                 |                 |
| and size.     |                 |                 |                 |
| Wave, ocean   |                 |                 |                 |
| current and   |                 |                 |                 |
| 150 MW wind   |                 |                 |                 |
| projects      |                 |                 |                 |
| would be      |                 |                 |                 |
| constructed   |                 |                 |                 |
| in one year,  |                 |                 |                 |
| 500 MW wind   |                 |                 |                 |
| projects in   |                 |                 |                 |
| two years,    |                 |                 |                 |
| and 1,000 MW  |                 |                 |                 |
| wind projects |                 |                 |                 |
| in three      |                 |                 |                 |
| years.        |                 |                 |                 |
| Projects      |                 |                 |                 |
| constructed   |                 |                 |                 |
| in one year   |                 |                 |                 |
| benefit from  |                 |                 |                 |
| the lower fee |                 |                 |                 |
| rate during   |                 |                 |                 |
| the first     |                 |                 |                 |
| year of       |                 |                 |                 |
| generation.   |                 |                 |                 |
| Electricity   |                 |                 |                 |
| sales for     |                 |                 |                 |
| each          |                 |                 |                 |
| generating    |                 |                 |                 |
| facility are  |                 |                 |                 |
| assumed to    |                 |                 |                 |
| occur over a  |                 |                 |                 |
| period of 20  |                 |                 |                 |
| years.        |                 |                 |                 |
+---------------+-----------------+-----------------+-----------------+

# 5.0 SENSITIVITY OF ANALYSIS TO KEY ASSUMPTIONS 

The fiscal impact analysis presented in this report is subject to
uncertainty due to data limitations and numerous assumptions made to
estimate Federal revenues and costs associated with MMS's proposed rule.
The analysis presented in this appendix assesses two factors of
particular interest to MMS: the sensitivity of the results to
assumptions regarding electricity prices and the impact on net Federal
revenues of the project revenues derived from the creation and sale of
renewable energy certificates (RECs). We also present an analysis of the
sensitivity of results to assumptions regarding other model inputs.

## 5.1 Electricity Price Sensitivity Analysis

Prices drive both the financial feasibility of projects and the
magnitude of operating fees, which are based on a fixed fraction of
electricity sales revenues. This analysis measures the effect on net
Federal revenues and project feasibility of adjusting prices across all
regions and years simultaneously. We make no attempt to adjust the
relative prices between regions, or to investigate how changes in the
pattern of prices in future years may affect results.

Table 5-1 illustrates the relationship between (1) price level (where
"0.0%" is the price used in the main analysis and "--50%" is 50 percent
lower than that price), (2) the present value of cumulative net Federal
revenues at a three percent discount rate, and (3) projects clearing the
11 percent hurdle rate and thus assumed to enter the construction phase.
Three rows are highlighted in the table, corresponding to off-peak,
on-peak, and average FERC prices. Off-peak and on-peak prices are
roughly 20 percent below and above (respectively) the average prices
used in our analysis. As observed in Table 5-1, if the analysis used
off-peak prices, estimated net Federal revenues would be roughly 55
percent lower, and 18 fewer projects in our forecast would be
constructed. On-peak prices would result in a 30 percent increase in net
revenues and five additional projects in our forecast would be
constructed.

Table 5-1

Effect of Electricity Price on Net Federal Revenues and Project
Financial Feasibility

  -------------- -------------- ----------- ------------ ----------- ------------
  **CHANGE IN    **3% DISCOUNT                           **CHANGE IN **PROJECTS
  PRICE LEVEL**  RATE                                    NET         CLEARING 11%
                 (MILLIONS)**                            REVENUES    HURDLE
                                                         FROM FERC   RATE**
                                                         AVERAGE**   

                 **Revenues**   **Costs**   **Net                    
                                            Revenues**               

  -50%           \$115.7        \$72.1      \$43.6       -87.8%      30

  -40%           \$152.2        \$73.5      \$78.7       -78.0%      33

  -30%           \$195.1        \$77.0      \$118.0      -67.0%      37

  FERC Off-Peak  \$245.1        \$84.0      \$161.2      -54.9%      40
  (-20%)                                                             

  -10%           \$330.2        \$85.5      \$244.6      -31.5%      48

  FERC Average   \$444.1        \$86.9      \$357.2      0.0%        58

  10%            \$501.6        \$88.2      \$413.3      15.7%       61

  FERC On-Peak   \$552.0        \$89.4      \$462.6      29.5%       63
  (20%)                                                              

  30%            \$597.7        \$91.9      \$505.8      41.6%       64

  40%            \$651.3        \$92.7      \$558.5      56.4%       67

  50%            \$700.9        \$93.3      \$607.6      70.1%       71

  60%            \$750.0        \$93.3      \$656.6      83.8%       73

  70%            \$800.2        \$93.4      \$706.8      97.9%       74

  80%            \$849.7        \$93.4      \$756.3      111.8%      76

  90%            \$895.9        \$93.4      \$802.5      124.7%      76

  100%           \$942.0        \$93.4      \$848.6      137.6%      76
  -------------- -------------- ----------- ------------ ----------- ------------

## 5.2 Sensitivity of Model Results to Inclusion of REC Payments

Rather than conduct a sensitivity analysis on a range of REC values, we
create a scenario in which REC payments are reduced to zero. The
resulting impacts vary across regions depending on the magnitude of
assumed regional REC payments. Those regions with higher per
kilowatt-hour payments, notably New England and New York, will be
significantly affected relative to those areas with lower or negligible
payments. Table 5-2 displays these prices as modeled. We note that the
input values themselves are subject to considerable uncertainty given
the limited amount of actual REC market data.

Table 5-2

Modeled REC Payments by Region

  --------------------------- -------------------------------------------
  **REGION**                  **MODELED REC PAYMENT (PER KWH)**

  New England                 \$0.05

  Mid-Atlantic                \$0.005

  New York                    \$0.03

  Florida                     \$0

  California                  \$0.005

  Oregon                      \$0.005

  Washington                  \$0.005

  Southeast                   \$0

  Gulf of Mexico              \$0
  --------------------------- -------------------------------------------

Table 5-3 indicates that the number of projects constructed under the
Intermediate No-REC scenario would be 43, 15 fewer than the scenario
when REC sales are included in project revenue.

Table 5-3

Results of Economic Viability Screening for Projects Operational by 2027

  ------------------ ----------------- ------------------ ------------------
  **Payment Case**   **Number of                          
                     Projects**                           

                     IRR \< 5 %        5 %                11 %
                                       [\<]{.underline}   [\<]{.underline}
                                       IRR \< 11 %        IRR

  Baseline           13                5                  58

  Low                13                5                  58

  Intermediate       13                5                  58

  High               13                8                  55

  Intermediate--No   17                6                  43
  REC                                                     
  ------------------ ----------------- ------------------ ------------------

Table 5-4 shows the undiscounted results of this model run for the 2008
to 2027 period, alongside the Intermediate scenario for comparison. On
an annual basis, the Intermediate-No REC scenario initially has higher
net revenues than the Intermediate scenario because of lower management
costs (without the REC, fewer projects clear hurdle rates); by 2027 the
lack of REC revenues cause the No REC scenario to lag behind in net
revenues by over \$27 million. The present value of this stream of net
revenues at a three percent discount rate is \$225 million; at a seven
percent discount rate the present value is \$110 million. Under the
Intermediate scenario, the present values at three and seven percent are
\$357 million and \$190 million respectively, indicating that the
presence of REC payments contributes a fairly significant percentage of
the net Federal revenues modeled in our analysis.

Table 5-4

Net Federal Revenues 2008 to 2027 (Undiscounted) for the Intermediate-No
REC Scenario

  ------------ ------------------- -------------- -------------- ----------------
  **YEAR**     **INTERMEDIATE-NO                                 **INTERMEDIATE
               REC (MILLIONS)**                                  (MILLIONS)**

               **Revenues**        **Costs**      **Net          **Net Revenues**
                                                  Revenues**     

  2008         \$0.15              \$6.27         -\$6.12        -\$6.34

  2009         \$0.32              \$6.54         -\$6.22        -\$6.46

  2010         \$0.55              \$6.64         -\$6.09        -\$6.32

  2011         \$1.03              \$6.85         -\$5.82        -\$5.12

  2012         \$1.36              \$7.01         -\$5.65        -\$4.68

  2013         \$1.71              \$5.92         -\$4.21        -\$2.19

  2014         \$1.90              \$5.78         -\$3.88        -\$1.44

  2015         \$2.01              \$6.01         -\$3.99        \$0.41

  2016         \$2.28              \$6.88         -\$4.60        \$3.08

  2017         \$6.26              \$7.33         -\$1.07        \$9.37

  2018         \$14.42             \$8.03         \$6.39         \$21.29

  2019         \$22.91             \$6.93         \$15.99        \$34.51

  2020         \$38.66             \$6.46         \$32.20        \$51.85

  2021         \$46.28             \$6.30         \$39.99        \$63.30

  2022         \$58.99             \$5.78         \$53.21        \$77.00

  2023         \$71.57             \$5.79         \$65.78        \$90.67

  2024         \$78.76             \$5.57         \$73.19        \$98.77

  2025         \$93.51             \$5.86         \$87.65        \$113.82

  2026         \$100.25            \$6.17         \$94.08        \$120.70

  2027         \$111.16            \$5.88         \$105.29       \$132.43
  ------------ ------------------- -------------- -------------- ----------------

#### 

## 5.3 Multivariate Analysis

Prices and REC payments are two of several variables that may influence
model results. In this last component of our uncertainty analysis, we
use an Excel-based program called Crystal Ball to identify those
variables whose uncertainty may have the largest effect on model
results.[^16] Crystal Ball is a graphically oriented forecasting and
risk analysis program that allows users to specify distributions for
variables with uncertain magnitudes, and, using a Monte-Carlo type
simulation, to assess the relative importance of each variable's
uncertainty in estimating model outputs. In our context, the program is
used to investigate the sensitivity of net Federal revenues (under the
Intermediate payment scenario) to variation in uncertain model
variables. In total, 15 variables are included in the Crystal Ball
analysis; the uncertainty associated with these variables is described
below.

[Financial Variables]{.underline}

-   **Debt Financing Share.** The debt/equity investment ratio is
    largely driven by the level of risk that debt and equity investors
    are willing to accept. Because offshore power projects are not yet
    an established market in the U.S., the response of investors is
    uncertain.

-   **Debt Rate.** The debt rate was selected based on current bond
    rates. These rates will change in future years; however, whether
    these changes will be positive or negative is uncertain. As the cost
    of capital on these investment-intensive projects changes, the
    profitability of those projects will change as well.

-   **Federal Tax Rate.** How the corporate Federal tax rate might
    change in future years is uncertain, but such changes may have
    pronounced effects on the Federal revenues estimated in this
    regulatory analysis.

-   **Hurdle Rates (2 variables).** Internal Rate of Return (IRR) hurdle
    rates determine the number of projects that apply for construction
    permits and the number that initiate construction (currently set at
    five and 11 percent, respectively). These rates therefore directly
    influence Federal net revenues. Depending on the returns that equity
    investors demand, these values may be considerably higher than
    estimated.

-   **Inflation.** Our analysis uses a point estimate for inflation of
    1.9 percent. Although there are both historical precedence for and
    forecasts indicating the validity of this estimate, a wide range of
    factors may cause the inflation rate to change.

[Project Revenue Variables]{.underline}

-   **Electricity Price.** Although regional prices may be more certain
    than REC values, small shifts in this variable can have dramatic
    consequences on both Federal revenues (through changes in operations
    fees) and project profitability.

-   **Production Tax Credits (PTCs).** Although PTCs are expected to be
    extended to future renewable projects (and expanded to include wave
    and current projects), it is uncertain whether such extensions will
    occur and whether the magnitude of the credit might change.

[Technology-Specific Variables]{.underline}

-   **Capacity Factors (3 variables).** The capacity factors for wind,
    wave, and current power were specified in the model based on
    existing information on the efficiency of onshore wind, offshore
    European facilities, and experimental wave and current facilities.
    Whether commercial scale operations in the U.S. will function at
    these levels is uncertain.

-   **Installed Capital Costs and Annual O&M Costs (4 variables).** Both
    modeled installed capital cost and operations and maintenance costs
    for the three technologies are highly uncertain and based on limited
    information (particularly in the cases of wave and current power).
    Whether modeled values are underestimates or overestimates is
    unknown.

For each of the variables listed above, we develop a range of likely
values under assumed probability distributions. Lacking greater
information on the distributions of these variables, all variables have
"triangle" distributions. Three points define a triangle distribution: a
minimum value, a maximum value, and a likeliest value (here, the value
used in our analysis). An example of a triangle distribution is
illustrated in Figure 5-1. In this example, the probability that the
debt financing share is either 40 percent or 80 percent is zero. As the
share moves from these low and high estimates toward 60 percent (the
approximate modeled value), the probability linearly increases, forming
a triangle shaped distribution. If greater information indicating the
distributions of these variables becomes available (e.g., indicating the
actual underlying distribution is uniform or normal), the analysis can
be adjusted accordingly.

Figure 5-1

Example of a Triangle Distribution

![](media/image3.png){width="3.1006944444444446in"
height="1.4784722222222222in"}

Table 5-5 summarizes the values used for the three points of the
triangle distribution for each of the above variables. These ranges were
developed using our professional judgment; this uncertainty analysis
could be refined if additional information were available that more
accurately characterizes the magnitude of variable uncertainty.

Table 5-5

Points Defining the Triangle Distribution of Uncertain Variables

  ------------------------------- ------------- ------------- -------------
  **ASSUMPTION**                  **LOW         **LIKELIEST   **HIGH
                                  ESTIMATE**    (REGULATORY   ESTIMATE**
                                                ANALYSIS      
                                                VALUE)**      

  **Financial Variables**         ** **         ** **         ** **

  Debt Financing Share            40%           60%           80%

  Debt Interest Rate              5.00%         6.86%         9.00%

  Federal Tax Rate                30%           35%           40%

  Lower Hurdle IRR                0%            5%            7%

  Upper Hurdle IRR                7%            11%           15%

  Inflation                       1.0%          1.9%          4.0%

  **Project Revenue Variables**                                

  Adjustment to Prices (per kWh)  -50%          0%            +50%

  PTC Value (per kWh)             \$0.00        \$0.02        \$0.04

  **Project-Specific Variables**                               

  Wind Capacity Factor            0.33          0.38          0.43

  Wave Capacity Factor            0.30          0.35          0.40

  Current Capacity Factor         0.75          0.80          0.85

  Average First Year Wind         \$2,267       \$2,667       \$3,067
  Installed Cost (per kW)                                     

  Wave/Current First Year         \$2,200       \$2,600       \$3,000
  Installed Cost (per kW)                                     

  Wind O&M (per kW-yr)            \$50          \$67          \$80

  Wave/Current O&M (per kW-yr)    \$100         \$127         \$150
  ------------------------------- ------------- ------------- -------------

The ranges of values developed for each of these variables, as listed in
Table 5-4, are used as inputs to the Crystal Ball analysis. This program
runs Monte Carlo trials that consider all possible values within these
designated ranges, with the assumed probability distribution influencing
the value selected in each trial. For this uncertainty analysis, a total
of 10,000 trials are run---each trial is independent and does not affect
the outcome of other trials. As shown in Figure 5-2, the outcomes for
all 10,000 trials result in a probability distribution of the net
Federal revenues, at a discount rate of three percent. Net revenues
under the Intermediate payment scenario from the regulatory analysis are
\$357 million, whereas the mean of the distribution below is roughly
\$333 million. The entire range of output values is from -\$9.4 million
to \$681 million.

Figure 5-2

Probability Distribution of Net Federal Revenues (2008 to 2027) Given
Variation of Assumptions, Discounted at 3 Percent, Variation in Price
Included

![](media/image4.png){width="5.009722222222222in"
height="2.832638888888889in"}

To assess which variables influence the results most significantly, the
simulation model provides sensitivity charts. Figure 5-3 shows a
sensitivity chart ranking the uncertain variables listed in Table 5-4
according to their importance to the net Federal revenues estimated in
our analysis (the values listed sum to one). Notably, variation in
electricity price explains the majority (83 percent) of the variation in
the discounted net revenues. Other significant parameters include the
wind capacity factor, PTC value, inflation, wind installed cost, debt
financing share, and upper hurdle IRR. Although not included in this
sensitivity analysis, adjusting the operating fee or other MMS fees
would result in commensurate changes to net revenues.

Figure 5-3

Sensitivity of Net Federal Revenues (Discounted at 3 Percent) to Model
Assumptions, Variation in Price Included

![](media/image5.wmf){width="5.166666666666667in"
height="2.9166666666666665in"}

Given the dominance of variations in price in the above sensitivity
analysis, we reran Crystal Ball with price held constant to more closely
investigate the sensitivity of net revenues to other parameters. As
shown in Figure 5-4, the probability distribution of the discounted net
Federal revenues without variations in price has a considerably narrower
range (from \$68 million to \$463 million). Figure 5-5 shows the
corresponding sensitivity chart; holding prices constant, variation in
the wind capacity factor now explains 48 percent of the variation in net
Federal revenues. For the remaining parameters, the pattern observed in
Figure 5-3 is now magnified in Figure 5-5 to more clearly assess the
relative importance of PTC value, inflation, wind installed cost, upper
hurdle IRR, and debt financing share.

Figure 5-4

Probability Distribution of Net Federal Revenues (2008 to 2027) Given
Variation of Assumptions, Discounted at 3 Percent, No Variation in Price

![](media/image6.png){width="5.009722222222222in"
height="2.832638888888889in"}

Figure 5-5

Sensitivity of Net Federal Revenues (Discounted at 3 Percent) to Model
Assumptions, Variation in Price Not Included

![](media/image7.wmf){width="5.166666666666667in"
height="2.9166666666666665in"}

# 

# 6.0 IMPACT OF PRODUCTION TAX CREDIT ON PROJECT VIABILITY 

Although Federal taxes are not included in the estimation of the net
revenues attributable to the proposed rule, the analysis makes two
important assumptions about tax policy that directly affect the
viability of projects:

-   The IRS will classify OCS wind, wave, and ocean current projects to
    allow an accelerated 5-year depreciation deduction.

-   Congress will renew the inflation-adjusted renewable energy
    Production Tax Credit (PTC) so that it remains available throughout
    the period of analysis.

If either the accelerated depreciation allowance or the PTC were no
longer available for future projects, the number of financially viable
projects would decline, which would directly affect the net revenue
results. Given the stop-and-start history of the PTC, it is a worthwhile
exercise to evaluate the importance of the PTC to project viability
within the model. Tables 6-1 through 6-5 present project performance
results assuming that the PTC is not available. Table 6-1 presents the
effect of applying our economic viability screen (discussed in Chapter
4) to the projects in the baseline and each of the three payment cases.
Tables 6-2 through 6-4 present the screening results for wind, wave, and
ocean current energy projects, respectively. Table 6-5 presents the
production capacity by technology for those projects that are forecast
to be operational between 2008 and 2027. Note that in our model the
elimination of the PTC changes only the number of wind energy projects
that are considered economically viable. No wave energy projects were
viable even with the PTC, so eliminating the credit does not change the
screening results, and all forecast ocean current energy projects
continue to exhibit an IRR greater than 11 percent.

Table 6-1

Results of Economic Viability Screening for Projects Operational by
2027, No-PTC Scenario

  ----------------- ----------------- ------------------ ------------------
  **Payment Case**  **Number of                          
                    Projects**                           

                    IRR \< 5 %        5 %                11 %
                                      [\<]{.underline}   [\<]{.underline}
                                      IRR \< 11 %        IRR

  Baseline          29                14                 33

  Low               29                14                 33

  Intermediate      31                12                 33

  High              31                12                 33
  ----------------- ----------------- ------------------ ------------------

Table 6-2

Results of Economic Viability Screening for Wind Projects Operational by
2027, No-PTC Scenario

  -------------- ------------ --------------- ------------------ ------------------
  **Payment      **Rated      **Number of                        
  Case**         Plant        Projects**                         
                 Capacity                                        
                 (MW)**                                          

                              IRR \< 5 %      5 %                11 %
                                              [\<]{.underline}   [\<]{.underline}
                                              IRR \< 11 %        IRR

  Baseline       150          12              2                  2

                 500          6               7                  10

                 1,000        2               5                  6

                 **Total**    **20**          **14**             **18**

  Low            150          12              2                  2

                 500          6               7                  10

                 1,000        2               5                  6

                 **Total**    **20**          **14**             **18**

  Intermediate   150          12              2                  2

                 500          7               6                  10

                 1,000        3               4                  6

                 **Total**    **22**          **12**             **18**

  High           150          12              2                  2

                 500          7               6                  10

                 1,000        3               4                  6

                 **Total**    **22**          **12**             **18**
  -------------- ------------ --------------- ------------------ ------------------

Table 6-3

Results of Economic Viability Screening for Wave Projects Operational by
2027, No-PTC Scenario

  ----------------- ----------------- ------------------ ------------------
  **Payment Case**  **Number of                          
                    Projects**                           

                    IRR \< 5 %        5 %                11 %
                                      [\<]{.underline}   [\<]{.underline}
                                      IRR \< 11 %        IRR

  Baseline          9                 0                  0

  Low               9                 0                  0

  Intermediate      9                 0                  0

  High              9                 0                  0
  ----------------- ----------------- ------------------ ------------------

Table 6-4

Results of Economic Viability Screening for Current Projects Operational
by 2027, No-PTC Scenario

  ----------------- ----------------- ------------------ ------------------
  **Payment Case**  **Number of                          
                    Projects**                           

                    IRR \< 5 %        5 %                11 %
                                      [\<]{.underline}   [\<]{.underline}
                                      IRR \< 11 %        IRR

  Baseline          0                 0                  15

  Low               0                 0                  15

  Intermediate      0                 0                  15

  High              0                 0                  15
  ----------------- ----------------- ------------------ ------------------

Table 6-5

Installed Capacity of Constructed Wind, Wave, and Current Projects
Operational by 2027, No-PTC Scenario

  ----------------- ---------------- ----------------- ------------------
  **Payment Case**  **Technology**   **Installed       
                                     Capacity of       
                                     Constructed       
                                     Projects (MW)**   

                                     With-PTC (Table   No-PTC
                                     4-5)              

  Baseline          Wind             25,200            12,300

                    Wave             0                 0

                    Current          480               480

                    **Total**        **25,680**        **12,780**

  Low               Wind             25,200            12,300

                    Wave             0                 0

                    Current          480               480

                    **Total**        **25,680**        **12,780**

  Intermediate      Wind             25,200            12,300

                    Wave             0                 0

                    Current          480               480

                    **Total**        **25,680**        **12,780**

  High              Wind             23,700            12,300

                    Wave             0                 0

                    Current          480               480

                    **Total**        **24,180**        **12,780**
  ----------------- ---------------- ----------------- ------------------

# 

# 

# 7.0 net revenues analysis

In accordance with OMB guidance, we estimated the present value of
cumulative net revenues in constant dollars for the Baseline, Low,
Intermediate, and High payment cases assuming real discount rates of
three and seven percent. These results were computed from project level
nominal revenues which were aggregated annually for years from 2008
through 2027, then deflated and discounted as end-of-year cash flows
back to 2008. Section 8(p)(2)(B) of OCSLA requires the distribution of
27 percent of fiscal revenues to the appropriate coastal states, when a
project is located partially or wholly in the area extending 3 nautical
miles seaward of state submerged lands. The revenue estimates reported
for this analysis were adjusted assuming that 40 percent of the projects
included in the development forecast would be subject to the revenue
sharing provision.

Table 7-1 presents these results, as of January 1, 2008. At both three
and seven percent, the present value net revenues are negative in the
Baseline and Low payment cases and significantly positive in the
Intermediate and High payment cases. Net revenues are negative in the
Baseline because no fees exist to generate revenues for the Federal
government, but inspection costs (under Corps management) are incurred
for any projects that may be constructed. Table 4-7 summarizes the
fiscal terms for the three payment cases. The estimated revenue flows to
the U.S. Treasury vary considerably among the payment cases. In the Low
payment case, which includes a project area-based rental fee, Federal
revenues are consistently lower than costs between 2008 and 2027,
resulting in negative discounted net revenues. In the Intermediate and
High payment cases, the increase in net revenues is explained by the
inclusion of capacity-based operating fees which are large in comparison
to other proposed payments to the Federal government. The operating fees
are calculated according to the following formula: **F** (annual
operating fee in \$ per year) **= M** (installed capacity in megawatts)
x **H** (8760 hours per year) x **c** (a capacity factor defined as the
actual production over a given period of time divided by the amount of
power a facility would have produced if it had run at full capacity) x
**P** (power price in \$ per megawatt-hour) x **r** (the operating fee
rate expressed as a fraction or decimal, similar to a royalty rate).
When estimating revenues for the Intermediate payment case, operating
fees are charged at a rate of one percent during the first two years of
the operations term, and at a rate of two percent thereafter. In the
High payment case, operating fees during the first two years of the
operations term are still charged at a rate of one percent, but escalate
to a rate of three percent for years three through eight, a rate of five
percent for years nine through 15, and a rate of 10 percent thereafter.
[]{.mark}

Tables 7-2 through 7-5 present the undiscounted nominal streams of
estimated annual Federal government revenues, costs, and net revenues
for each case during the period 2008-2027. In the Baseline case, the
Federal government does not collect any revenues but continues to incur
costs associated with the oversight required by existing law and
regulation (as described in Section 3, limited to Corps costs associated
with wind energy projects). Note that in 2014 and 2015 we assume zero
government costs based on the assumed lack of project construction
activity during that two-year period (see Table 2-6). The Low,
Intermediate, and High payment cases all exhibit a general pattern of
increasing net revenues over the period of analysis, beginning with a
period of negative net revenues. These negative net revenues largely
reflect MMS costs associated with the first project applications in the
years prior to the collection of any operating fee revenues, as well as
programmatic costs (e.g., preparation for the anticipated 2012 lease
sale) that are not expected to exist in later years. In the Low payment
case, the program experiences a longer period of negative net revenues
in comparison to the other cases, in part due to the lack of any
operating fee revenues to offset costs in the years when the first
projects begin generating electricity.

One additional result of note in the annual revenue and cost estimates
is the large increase in net revenues in the Intermediate and High
payment cases beginning in 2018. This increase is associated with the
presumed 2012 lease sale, which would initiate development activity for
a large number of projects, culminating in a surge in construction
activity beginning in 2018. Since MMS begins collecting operating fees
during the first year of project construction, revenues would increase
accordingly.

Tables 7-6 through 7-8 report the present value of cumulative net
revenues in constant dollars, by payment case, for each of the three
technologies considered in the analysis (wind, wave, and ocean current
energy). Tables 7-9 through 7-11 report the present value of cumulative
net revenues in constant dollars, by case, for each of the regions
considered in the analysis (Atlantic, Gulf of Mexico, and Pacific).[^17]
These results highlight the dominance of wind energy projects and the
Atlantic region in the project forecast. Wind energy projects comprise
approximately 70 percent of all projects in the development forecast and
are, on average, much larger in generating capacity terms than wave or
ocean current projects. In the Intermediate payment case, wind energy
projects account for over 99 percent of cumulative net revenues, while
Atlantic region projects account for more than 80 percent of cumulative
net revenues. Although no wave projects are forecast to be constructed
between 2008 and 2027 (see Table 4-3), wave projects have negative
discounted net revenues in the Low, Intermediate, and High payment cases
during that period. This result is attributable to the inclusion of
three wave projects in our project forecast with construction occurring
between 2028 and 2036. During the period of analysis (2008 to 2027),
these three projects cost MMS more in pre-construction management
expenses than they provide in pre-construction fees. The net revenues
associated with ocean current projects under all payment cases are also
negative. Compared to wind projects, current projects generate
relatively low per project Federal revenues (due to their lower
production capacities), whereas their per project Federal costs are very
similar. As such, although these projects may be commercially viable,
modeling results indicate that they do not contribute positive Federal
net revenues in any of the payment cases.

Table 7-1

Present Value of Cumulative Net Revenues (Millions) in Constant 2008 \$

All Projects, 2008-2027

  ----------------------- ----------------------- -----------------------
  **Payment Case**        **Real Discount Rate**  

                          **3%**                  **7%**

  **Baseline**            -\$9.33                 -\$7.78

  **Low**                 -\$57.33                -\$46.54

  **Intermediate**        \$357.18                \$189.88

  **High**                \$537.68                \$290.59
  ----------------------- ----------------------- -----------------------

Table 7-2

Annual Revenues and Costs (Millions) in Undiscounted Nominal \$

All Projects, Baseline Case

  ----------------- ----------------- ----------------- -----------------
  **Year**          **Revenues**      **Costs**         **Net Revenues**

  2008              \$0.00            \$0.63            -\$0.63

  2009              \$0.00            \$2.54            -\$2.54

  2010              \$0.00            \$1.43            -\$1.43

  2011              \$0.00            \$1.11            -\$1.11

  2012              \$0.00            \$0.95            -\$0.95

  2013              \$0.00            \$0.48            -\$0.48

  2014              \$0.00            \$0.00            \$0.00

  2015              \$0.00            \$0.00            \$0.00

  2016              \$0.00            \$0.63            -\$0.63

  2017              \$0.00            \$0.32            -\$0.32

  2018              \$0.00            \$0.32            -\$0.32

  2019              \$0.00            \$0.48            -\$0.48

  2020              \$0.00            \$0.48            -\$0.48

  2021              \$0.00            \$0.48            -\$0.48

  2022              \$0.00            \$0.48            -\$0.48

  2023              \$0.00            \$0.48            -\$0.48

  2024              \$0.00            \$0.48            -\$0.48

  2025              \$0.00            \$0.63            -\$0.63

  2026              \$0.00            \$0.32            -\$0.32

  2027              \$0.00            \$0.32            -\$0.32
  ----------------- ----------------- ----------------- -----------------

Table 7-3

Annual Revenues and Costs (Millions) in Undiscounted Nominal \$

All Projects, Low Payment Case

  ----------------- ----------------- ----------------- -----------------
  **Year**          **Revenues**      **Costs**         **Net Revenues**

  2008              \$0.16            \$6.50            -\$6.34

  2009              \$0.35            \$6.82            -\$6.46

  2010              \$0.58            \$6.89            -\$6.32

  2011              \$1.14            \$7.14            -\$6.00

  2012              \$1.47            \$7.30            -\$5.84

  2013              \$1.82            \$6.10            -\$4.28

  2014              \$2.01            \$5.87            -\$3.85

  2015              \$2.21            \$6.13            -\$3.91

  2016              \$2.65            \$7.19            -\$4.54

  2017              \$2.62            \$7.58            -\$4.97

  2018              \$2.86            \$8.35            -\$5.50

  2019              \$3.07            \$6.95            -\$3.88

  2020              \$3.31            \$6.49            -\$3.18

  2021              \$3.54            \$6.33            -\$2.80

  2022              \$3.77            \$5.82            -\$2.05

  2023              \$4.00            \$5.83            -\$1.83

  2024              \$4.23            \$5.61            -\$1.39

  2025              \$4.36            \$5.90            -\$1.54

  2026              \$4.24            \$6.22            -\$1.97

  2027              \$4.01            \$6.03            -\$1.93
  ----------------- ----------------- ----------------- -----------------

Table 7-4

Annual Revenues and Costs (Millions) in Undiscounted Nominal \$

All Projects, Intermediate Payment Case

  ----------------- ----------------- ----------------- -----------------
  **Year**          **Revenues**      **Costs**         **Net Revenues**

  2008              \$0.16            \$6.50            -\$6.34

  2009              \$0.35            \$6.82            -\$6.46

  2010              \$0.58            \$6.89            -\$6.32

  2011              \$2.02            \$7.14            -\$5.12

  2012              \$2.62            \$7.30            -\$4.68

  2013              \$3.91            \$6.10            -\$2.19

  2014              \$4.43            \$5.87            -\$1.44

  2015              \$6.54            \$6.13            \$0.41

  2016              \$10.27           \$7.19            \$3.08

  2017              \$16.96           \$7.58            \$9.37

  2018              \$29.65           \$8.35            \$21.29

  2019              \$41.46           \$6.95            \$34.51

  2020              \$58.34           \$6.49            \$51.85

  2021              \$69.64           \$6.33            \$63.30

  2022              \$82.82           \$5.82            \$77.00

  2023              \$96.49           \$5.83            \$90.67

  2024              \$104.38          \$5.61            \$98.77

  2025              \$119.72          \$5.90            \$113.82

  2026              \$126.92          \$6.22            \$120.70

  2027              \$138.36          \$6.03            \$132.42
  ----------------- ----------------- ----------------- -----------------

Table 7-5

Annual Revenues and Costs (Millions) in Undiscounted Nominal \$

All Projects, High Payment Case

  ----------------- ----------------- ----------------- -----------------
  **Year**          **Revenues**      **Costs**         **Net Revenues**

  2008              \$0.20            \$6.50            -\$6.30

  2009              \$0.40            \$6.82            -\$6.42

  2010              \$0.65            \$6.89            -\$6.24

  2011              \$2.12            \$7.14            -\$5.02

  2012              \$2.82            \$7.30            -\$4.49

  2013              \$5.28            \$6.10            -\$0.82

  2014              \$6.29            \$5.87            \$0.42

  2015              \$8.66            \$6.13            \$2.53

  2016              \$12.48           \$7.19            \$5.30

  2017              \$21.35           \$7.58            \$13.77

  2018              \$37.57           \$8.35            \$29.21

  2019              \$51.34           \$6.95            \$44.39

  2020              \$77.74           \$6.49            \$71.25

  2021              \$93.66           \$6.33            \$87.34

  2022              \$114.36          \$5.81            \$108.55

  2023              \$131.90          \$5.82            \$126.08

  2024              \$145.93          \$5.60            \$140.32

  2025              \$176.77          \$5.89            \$170.88

  2026              \$193.57          \$6.21            \$187.36

  2027              \$218.91          \$6.02            \$212.98
  ----------------- ----------------- ----------------- -----------------

Table 7-6

Present Value of Cumulative Net Revenues (Millions) in Constant 2008 \$

Wind Projects, 2008-2027

  ----------------------- ----------------------- -----------------------
  **Payment Case**        **Real Discount Rate**  

                          **3%**                  **7%**

  **Baseline**            -\$6.69                 -\$5.55

  **Low**                 -\$38.52                -\$32.23

  **Intermediate**        \$365.22                \$198.17

  **High**                \$539.90                \$295.67
  ----------------------- ----------------------- -----------------------

Table 7-7

Present Value of Cumulative Net Revenues (Millions) in Constant 2008 \$

Wave Projects, 2008-2027

  ----------------------- ----------------------- -----------------------
  **Payment Case**        **Real Discount Rate**  

                          **3%**                  **7%**

  **Baseline**            \$0                     \$0

  **Low**                 -\$1.11                 -\$0.59

  **Intermediate**        -\$1.01                 -\$0.54

  **High**                -\$0.99                 -\$0.54
  ----------------------- ----------------------- -----------------------

Table 7-8

Present Value of Cumulative Net Revenues (Millions) in Constant 2008 \$

Ocean Current Projects, 2008-2027

  ----------------------- ----------------------- -----------------------
  **Payment Case**        **Real Discount Rate**  

                          **3%**                  **7%**

  **Baseline**            -\$2.41                 -\$2.09

  **Low**                 -\$17.70                -\$13.72

  **Intermediate**        -\$7.04                 -\$7.74

  **High**                -\$1.22                 -\$4.54
  ----------------------- ----------------------- -----------------------

Table 7-9

Present Value of Cumulative Net Revenues (Millions) in Constant 2008 \$

Atlantic Region Projects, 2008-2027

  ----------------------- ----------------------- -----------------------
  **Payment Case**        **Real Discount Rate**  

                          **3%**                  **7%**

  **Baseline**            -\$6.69                 -\$5.80

  **Low**                 -\$47.64                -\$39.30

  **Intermediate**        \$283.40                \$151.81

  **High**                \$460.75                \$251.41
  ----------------------- ----------------------- -----------------------

Table 7-10

Present Value of Cumulative Net Revenues (Millions) in Constant 2008 \$

Gulf Region Projects, 2008-2027

  ----------------------- ----------------------- -----------------------
  **Payment Case**        **Real Discount Rate**  

                          **3%**                  **7%**

  **Baseline**            -\$0.52                 -\$0.39

  **Low**                 -\$2.27                 -\$1.73

  **Intermediate**        \$12.99                 \$6.47

  **High**                \$19.60                 \$10.02
  ----------------------- ----------------------- -----------------------

Table 7-11

Present Value of Cumulative Net Revenues (Millions) in Constant 2008 \$

Pacific Region Projects, 2008-2027

  ----------------------- ----------------------- -----------------------
  **Payment Case**        **Real Discount Rate**  

                          **3%**                  **7%**

  **Baseline**            -\$2.12                 -\$1.59

  **Low**                 -\$7.42                 -\$5.51

  **Intermediate**        \$60.79                 \$31.61

  **High**                \$57.34                 \$29.17
  ----------------------- ----------------------- -----------------------

#  8.0 qualitative analysis of costs and revenues associated with alternate uses of existing ocs facilities

In addition to the promotion of alternative energy production on the
OCS, other activities are anticipated by the EPAct amendments to the OCS
Lands Act; namely the alternate use of existing facilities currently or
previously used for activities authorized by the Act. MMS is
establishing a regulatory program that will address alternative energy
activities as well as energy- and non-energy related alternate use
activities on the OCS. As part of its rulemaking process, MMS is
undertaking a quantitative assessment of the revenues and costs of the
proposed program with respect to alternative energy activities; an
analysis made possible by MMS\'s ability to create a forecast of future
alternative energy project development. The nature and scope of interest
in alternate uses of existing facilities is less certain, making it
difficult to analyze future revenues and costs quantitatively.
Therefore, MMS is undertaking a qualitative analysis of these potential
impacts.

## 8.1 Alternate Uses of Existing Facilities

As reported in the final Programmatic Environmental Impact Statement
(EIS) for the Alternative Energy and Alternate Use Program, nearly 1,100
existing oil and gas platforms are expected to cease production over the
next 15 years, creating, on paper, numerous potential opportunities for
alternate uses. Historically, removal of retired platforms has comprised
disassembly and onshore disposal of structural materials as scrap metal.
A small percentage have been converted to artificial reefs (e.g.,
through the federal Rigs-to-Reefs program). While the reef program will
continue, there may be interest going forward in one or more of the
following alternate uses of some of these facilities (some of which may
be possible while a platform is still operational).

### 8.1.1 Aquaculture

The large and growing demand for seafood, the substantial role of
aquaculture as a supplement to native fisheries, and the fact that the
best coastal locations for aquaculture are already developed suggest
that moving aquaculture offshore may be an attractive opportunity. Use
of the existing infrastructure offered by oil and gas platforms could
expedite the growth of this sector. However, it should be noted that
there are legislative proposals under consideration to establish a
Federal regulatory program for offshore aquaculture activities that
would be administered by the Department of Commerce. If such legislation
were to become law, it is uncertain what regulatory role MMS would
serve, and whether MMS jurisdiction under subsection 8(p) of the OCSLA
would still be applicable. Accordingly, potential offshore aquaculture
activities may eventually have no fiscal impacts in the context of this
regulation.

### 8.1.2 Oil and gas support functions

A former oil and gas platform could serve to support the operations of
existing or new platforms. A platform located at an intermediate
location relative to multiple facilities further from shore could be
used for fuel storage or as a supply depot, potentially reducing the
cost of regularly transporting these materials offshore.

### 8.1.3 Education and research

Education or research institutions with a focus on the marine
environment might be interested in establishing permanent or
semi-permanent offshore facilities to advance their missions. Retired
platforms might serve as cost-effective operational bases, particularly
for activities that require extended stays at sea. As part of these
activities, or independently, these facilities could also house various
types of remote monitoring instrumentation (e.g., for military or
homeland security purposes or for the collection of meteorological or
other environmental data).

### 8.1.4 Desalination

If the need for, or opportunity to construct, a desalination facility
were to exist in an area where siting such a facility might be
difficult, an offshore platform (and associated pipelines) might serve
as a suitable foundation for the construction of a desalination plant.

### 8.1.5 Telecommunications

As the offshore oil and gas industry becomes increasingly data
intensive, with sophisticated techniques generating exploration and
production information that must be transmitted to shore along with
routine communications, offshore platforms that are no longer in use
might be attractive as sites to locate centralized data and
communications centers, or as links in larger communications networks.

### 8.1.6 Medical care

Offshore activities present numerous worker health and safety risks.
Offshore platforms might therefore have a valuable alternate use as
medical care facilities, especially if they were set up to provide
emergency services for the stabilization of serious injuries prior to
transfer to an onshore facility.

### 8.1.7 Leisure and recreation

The popularity of the coastal and marine environments for leisure and
recreational activities suggests that an entrepreneur might see an
offshore platform as an opportunity to develop a hotel or a staging area
for shorter-term activities (e.g., scuba diving).

## 8.2 Potential Federal revenues

The types of revenues that alternate uses of OCS facilities could
generate are similar to those associated with alternative energy
projects, including rental and other payments to MMS for access to and
use of the OCS. The scale of these revenues over the period 2008 to 2027
will be a function of how many alternate uses actually occur and whether
they are of a type likely to compel MMS to seek rental or other
payments. For example, purely commercial uses (desalination, leisure and
recreation, etc.) might generate taxable income and would almost
certainly require some form of payment to MMS, but the level of such
activity during the period of analysis is likely going to be very low.
As a result, revenue collections can be expected to be very low. Other
types of uses, such as education and research or medical care, might be
less likely to be required to make rental payments (and almost certainly
would not generate taxable income or be subject to operating fee
payments). This might be particularly true if the alternate use were in
support of, and enhanced the value of, oil and gas-related activities.
Overall, in contrast to the number of inquiries MMS has received
regarding potential alternative energy projects on the OCS, the level of
interest in alternate use activities has been extremely low. This,
combined with the factors described above, suggests that federal
revenues from alternate uses of OCS facilities will be relatively
insignificant, at best, over the next 20 years.

## 8.3 Potential Federal costs

Federal programmatic costs attributable to alternate uses of OCS
facilities will be a direct function of the level of activity. As with
alternative energy projects, alternate use projects will require
NEPA-compliant impact studies subject to MMS\'s review and approval.
However, since the studies will not be assessing any significant new
construction, it may be possible to build off of existing NEPA reviews
of the original structures when the alternate use is not expected to
result in a new or different impact. For example, a second archeological
review of the site would likely be unnecessary in most if not all cases.
This will serve to reduce program costs to some degree. At the same
time, the first instance in which a particular alternate use is proposed
may require closer scrutiny given MMS\'s lack of experience evaluating
such a use. Over time, reviews of similar projects may occur more
quickly (i.e., at lower cost) due to learning effects. In general, with
relatively little expected activity, the costs are likely to be low.

## 8.4 Qualitative assessment of net fiscal impact

Whether revenues associated with any one project will exceed the program
costs associated with the review of that project will depend on factors
such as the project type and whether the same or similar projects have
previously been proposed or approved (making it easier, and less costly,
to review the project application). Non-commercial projects, such as
educational or medical facilities, which are unlikely to generate
significant, if any, Federal revenues might at best be subject to
payments set at a level intended only to offset the Federal
government\'s costs. Commercially-oriented projects are more likely to
have a net positive impact (i.e., generation of revenues over the life
of the project that exceed project-specific costs). The inability to
evaluate whether the net fiscal impact of all alternate use projects
that might occur over the next 20 years will be positive or negative is
mitigated by the fact that, whatever the impact, it will likely be
relatively small in the context of the net fiscal impacts of all
projects contemplated under subsection 8(p) of OCSLA (alternative energy
and alternate use). In absolute terms, the fiscal impacts (revenues and
costs) associated with alternative energy projects on the OCS are
expected to be much larger than those associated with alternate uses of
existing facilities.

# 9.0 Distribution of fiscal impacts

Under the requirements of the Regulatory Flexibility Act (RFA) of 1980,
as amended by the Small Business Regulatory Enforcement Fairness Act of
1996 (SBRFA) and Executive Order 13272 ("Proper Consideration of Small
Entities in Agency Rulemaking"), Federal agencies must consider the
potential distributional impact of new rules on small businesses, small
governmental jurisdictions, and small organizations. MMS is required to
prepare a regulatory flexibility analysis and take other steps to assist
small entities, unless it certifies that the rule will not have a
"significant economic impact on a substantial number of small entities."
Certification of the rule must include a statement providing the factual
basis for this determination.

The Small Business Administration (SBA) provides guidelines on the
analytical process for assessing the impact of a particular rulemaking
on small entities.[^18] The first requirement of a RFA/SBRFA assessment
is a screening analysis to determine whether a rule is likely to have a
significant economic impact on a substantial number of small entities.
The screening analysis includes:

1.  Identifying the types of small entities subject to the rule's
    requirements (e.g. businesses, nonprofit organizations, governments,
    etc.) to determine whether the number of small entities affected is
    "substantial."

2.  Identifying the actions a small entity will have to take to comply
    with the requirements of the rule (e.g. installation of new
    technology, revised record keeping system) to determine whether the
    potential impacts are of sufficient magnitude and scope to be
    considered "significant."

The remainder of this section provides the results of MMS's screening
analysis used to determine whether it can certify the rule. This
screening analysis only addresses the impacts of the rule governing
payments for access to and use of the OCS for alternative energy
projects or other uses.

## 9.1 Number of small entities to which the rule will apply

The North American Industry Classification System (NAICS) code for the
industry affected by the proposed rule is 221119 (Other Electric Power
Generation). This classification includes generation that does not
depend on fossil fuels, nuclear power, or hydroelectric power. An entity
within this classification is "small" if it is \"primarily engaged in
the generation, transmission, and/or distribution of electric energy for
sale and its total electric output for the preceding fiscal year did not
exceed four million megawatt hours" (MWh). Many of the entities subject
to the rule will likely exist, during the period of analysis, solely to
develop one or more offshore alternative energy projects that combined
will not have a total electric output greater than 4 million MWh
(corresponding to an offshore wind project with a rated capacity of more
than 1,100 MW, which is larger than the largest project included in the
MMS forecast for the next 20 years). Some entities, either through a
combination of projects or through the incorporation of offshore
alternative energy projects into a larger portfolio of electricity
generating stations, will exceed the four million MWh threshold.

Given the immaturity of the offshore alternative energy industry, it is
difficult to develop an accurate count of the number of entities that
will or may be subject to this rule in order to determine whether the
rule will affect a \"substantial\" number of small entities. Several
companies have formally or informally expressed interest in being
granted access to the OCS for electricity generation purposes. At least
40 to 50 entities are identifiable as potential project or technology
developers with a focus on utilizing offshore wind, wave, or ocean
current resources. The U.S. Census Bureau\'s 2002 Economic Census
reported 411 entities within NAICS code 221119. However, for the
purposes of this analysis MMS assumes that most of the relevant entities
will be considered \"small,\" and therefore can conclude that a
substantial number of small entities will be affected.

It is possible that the proposed rule may eventually govern hydrogen
production, affecting entities that fall under NAICS Code 325120,
Industrial Gas Manufacturing. (This general industry classification
covers establishments primarily engaged in manufacturing industrial
organic and inorganic gases in compressed, liquid, and solid forms.)
However, it is unlikely that hydrogen will be produced on the OCS in
significant amounts during the 20-year period of analysis, and MMS has
no means to predict what kinds of entities would likely be involved in
hydrogen production, given the lack of proposals for projects that would
produce hydrogen.

## 9.2 Economic impact of the rule on affected small entities

The significance of the impact on small entities is assessed in this
case by comparing the payments required under the rule to the total
revenues generated by the subject entities. For this analysis, MMS
considers all project revenues and payments to the Federal government
associated with the 52 projects that meet the target IRR value,
regardless of when they occur (i.e., the analysis considers revenues and
payments that occur post-2027). For each payment case, Table 9-1
presents the annualized per project payments and annualized per project
revenues. Annualized values are estimated over the lifetime of the
project as modeled in this report. Dividing payments by revenues
provides a conservative estimate of the impact of compliance costs on
small entities because it assumes (1) all of the affected projects are
undertaken by small entities, (2) each entity undertakes a single
project, and (3) the entire revenues for each entity are derived solely
from this renewable energy project (i.e., the companies involved to not
have groups of projects or other business interests). Therefore, the
results of this screening analysis are more likely to overstate than
understate the significance of compliance costs to affected entities.

As shown in Table 9-1, the highest ratio of payments to revenues for a
single project under the Intermediate payment case is 2.1 percent, while
the lowest ratio is 0.81 percent, depending on the discount rate
applied. The average ratio across all projects in the Intermediate
payment case is 1.2 percent and 1.4 percent, applying discount rates of
three and seven percent respectively. The highest ratio of 4.1 percent
occurs under the High payment case assuming a discount rate of seven
percent.

Table 9-1

Significance of Compliance Costs

+-----------+-------------------+-------------------+------------------+
| **Payment | **Annualized      | **Annualized      | **Ratio of       |
| Case**    | Payments**        | Revenues**        | Payments to      |
|           |                   |                   | Revenues**       |
+-----------+-------------------+-------------------+------------------+
| **3%      |                   |                   |                  |
| Discount  |                   |                   |                  |
| Rate**    |                   |                   |                  |
+-----------+-------------------+-------------------+------------------+
| **B       | \$0               | \$72,300,000      | 0.00%            |
| aseline** |                   |                   |                  |
|           |                   | (\$7,000,000 -    |                  |
|           |                   | \$224,000,000)    |                  |
+-----------+-------------------+-------------------+------------------+
| **Low**   | \$32,400          | \$72,300,000      | 0.04%            |
|           |                   |                   |                  |
|           | (\$9,680 -        | (\$7,000,000 -    | (0.03% - 0.15%)  |
|           | \$84,100)         | \$224,000,000)    |                  |
+-----------+-------------------+-------------------+------------------+
| **Inter   | \$882,000         | \$72,300,000      | 1.2%             |
| mediate** |                   |                   |                  |
|           | (\$113,000 -      | (\$7,000,000 -    | (0.81% - 1.7%)   |
|           | \$2,350,000)      | \$224,000,000)    |                  |
+-----------+-------------------+-------------------+------------------+
| **High**  | \$2,140,000       | \$72,900,000      | 2.9%             |
|           |                   |                   |                  |
|           | (\$254,000 -      | (\$7,000,000 -    | (2.3% - 3.7%)    |
|           | \$5,780,000)      | \$224,000,000)    |                  |
+-----------+-------------------+-------------------+------------------+
| **7%      |                   |                   |                  |
| Discount  |                   |                   |                  |
| Rate**    |                   |                   |                  |
+-----------+-------------------+-------------------+------------------+
| **B       | \$0               | \$42,600,000      | 0.00%            |
| aseline** |                   |                   |                  |
|           |                   | (\$3,970,000 -    |                  |
|           |                   | \$125,000,000)    |                  |
+-----------+-------------------+-------------------+------------------+
| **Low**   | \$28,000          | \$42,600,000      | 0.07%            |
|           |                   |                   |                  |
|           | (\$7,900 -        | (\$3,970,000 -    | (0.04% - 0.22%)  |
|           | \$78,300)         | \$125,000,000)    |                  |
+-----------+-------------------+-------------------+------------------+
| **Inter   | \$604,000         | \$42,600,000      | 1.4%             |
| mediate** |                   |                   |                  |
|           | (\$71,800 -       | (\$3,970,000 -    | (0.92% - 2.1%)   |
|           | \$1,720,000)      | \$125,000,000)    |                  |
+-----------+-------------------+-------------------+------------------+
| **High**  | \$1,310,000       | \$43,000,000      | 3.1%             |
|           |                   |                   |                  |
|           | (\$148,000 -      | (\$3,970,000 -    | (2.3% - 4.1%)    |
|           | \$3,720,000)      | \$125,000,000)    |                  |
+-----------+-------------------+-------------------+------------------+
| Note: The |                   |                   |                  |
| center    |                   |                   |                  |
| value in  |                   |                   |                  |
| each cell |                   |                   |                  |
| indicates |                   |                   |                  |
| the       |                   |                   |                  |
| average   |                   |                   |                  |
| across    |                   |                   |                  |
| all       |                   |                   |                  |
| projects  |                   |                   |                  |
| under     |                   |                   |                  |
| that      |                   |                   |                  |
| payment   |                   |                   |                  |
| case. The |                   |                   |                  |
| range     |                   |                   |                  |
| provided  |                   |                   |                  |
| below in  |                   |                   |                  |
| pa        |                   |                   |                  |
| rentheses |                   |                   |                  |
| r         |                   |                   |                  |
| epresents |                   |                   |                  |
| the       |                   |                   |                  |
| minimum   |                   |                   |                  |
| and       |                   |                   |                  |
| maximum   |                   |                   |                  |
| values    |                   |                   |                  |
| across    |                   |                   |                  |
| the same  |                   |                   |                  |
| projects. |                   |                   |                  |
+-----------+-------------------+-------------------+------------------+

## 9.3 Initial Regulatory Flexibility Analysis

This section provides the information required for an Initial Regulatory
Flexibility Analysis (IRFA). Specifically, section 603 of the RFA
requires a discussion of each of the following elements:

1.  A description of the reasons why action by the agency is being
    considered;

2.  A succinct statement of the objectives of, and legal basis for, the
    proposed rule;

3.  A description of, and where feasible, an estimate of the number of
    small entities to which the proposed rule will apply;

4.  A description of the projected reporting, record-keeping and other
    compliance requirements of the proposed rule, including an estimate
    of the classes of small entities that will be subject to the
    requirement and the type of professional skills necessary for
    preparation of the report or record;

5.  An identification, to the extent practicable, of all relevant
    Federal rules which may duplicate, overlap or conflict with the
    proposed rule;

6.  A description of any significant alternatives to the proposed rule
    that accomplish the stated objectives of applicable statutes and
    that minimize any significant economic impact of the proposed rule
    on small entities, such as,

    -   The establishment of different compliance or reporting
        requirements or timetables that take into account the resources
        available to small entities;

    -   The clarification, consolidation, or simplification of
        compliance and reporting requirements under the rule for such
        small entities;

    -   The use of performance rather than design standards; and,

    -   An exemption from coverage of the rule, or any part thereof, for
        such small entities.

As discussed in Section 1, the EPAct, specifically section 388, amended
the OCS Lands Act to authorize the Secretary of the Interior to issue
leases, easements, or rights-of-way on the OCS for developing or
supporting the production of energy resources other than oil and gas and
to authorize other energy and marine-related activities that involve the
use of existing facilities on the OCS. The EPAct also required the
Department of the Interior to develop any necessary regulations to
implement this new authority. On March 20, 2006, the Secretary
officially delegated this new authority, and responsibility for
developing any necessary regulations, to the MMS.

The importance of these regulations stems from the growing interest in
harnessing the energy production potential that is available on the OCS
and the current lack of a formal system to facilitate activity. Prior to
the EPAct, the Federal government did not have clear authority to seek
payment for private interests\' access to and use of Federal submerged
lands. These regulations will serve an important social purpose by
establishing a payment structure to ensure a fair return to the United
States for any lease, easement, or right-of-way granted; by creating a
comprehensive "cradle-to-grave" regulatory program with provisions for
regular inspections and environmental monitoring; and by providing a
degree of regulatory certainty to those proposing, planning, or
potentially financing an offshore alternative energy project.

As discussed in Section 7.1, given the immaturity of the offshore
alternative energy industry, it is difficult to characterize and count
of the number of entities that will or may be subject to this rule. At
least 40 to 50 entities are identifiable as potential project or
technology developers with a focus on utilizing offshore wind, wave, or
ocean current resources. For the purposes of this analysis MMS assumes
that most of the relevant entities will be considered \"small.\"

The compliance requirements and associated costs of the proposed
regulation are discussed in detail in Sections 4 and 5 of this report.
MMS considers three possible fiscal term cases, which vary in terms of
the minimum bid or acquisition fee, lease rental terms, easement rental
terms, and operating fees. The terms do not vary depending on the size
of the applicant; however, as noted above, most of the entities entering
this industry over the next 20 years are likely to be small.

We note that these regulations were developed knowing that the majority
of affected entities would be small entities. Alternatives proposed in
the regulations to address the needs of small entities include:

-   The proposed rule allows alternative compliance as appropriate.
    Small entities may propose alternate reporting requirements and MMS
    may accept if human safety and the environment are not compromised.
    Other regulatory requirements may also be revised.

-   Financial assurance requirements were drafted with maximum
    flexibility so they would not pose an unnecessary burden on small
    entities.

As discussed in Section 1, the proposed rule is unlikely to duplicate,
overlap with, or conflict with other Federal rules. EPAct granted to the
Secretary of the Interior (who delegated to MMS) discretionary authority
to authorize and regulate alternative energy activities on the OCS only
to the extent such activities were not previously authorized by other
applicable law. Therefore, through the passage of EPAct, Congress
ensured that there would be no overlapping areas of Federal jurisdiction
on the OCS for alternative energy projects.

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Offshore Wind Generation. A Report to the Renewables Advisory Board and
the UK Department of Trade and Industry.

Previsic, M. 2004a. E2I EPRI Assessment: Offshore Wave Energy Conversion
Devices. Report E2I EPRI WP-004-US-Rev 1. June 16.

\_\_\_\_\_\_\_\_\_\_. 2004b. System Level Design, Performance and
Costs - Oregon State Offshore Wave Power Plant. Report E2I EPRI
Global-WP-006-OR Rev 1. November 30.

Wright, S.D., A.L. Rogers, J.F. Manwell, and A. Ellis. 2002.
Transmission Options for Offshore Wind Farms in the United States.
Presented at the American Wind Energy Association (AWEA) Windpower 2002
Conference.

**APPENDIX A MODEL DESCRIPTION**

This Appendix provides a description of IEc's Excel-based cash flow
model used to estimate Federal revenues, costs, and net revenues
associated with the proposed rule under different sets of fiscal (i.e.,
payment) terms (referred to in this Appendix as \"scenarios\").
Structurally, the Excel model contains 12 primary worksheets:

-   Worksheets 1 through 3 contain parameter information used by the
    model.

-   Worksheets 4 and 5 create project cash flow (for 2008 to 2027
    projects) and MMS payment (for 2028 to 2036) worksheets for
    project/scenario combinations using parameter information.

-   Worksheet 6 displays project-specific financial performance
    information for each project.

-   Worksheets 7 and 8 include the information and calculations
    associated with the estimation of government revenues and MMS costs
    on a project- and year-specific basis.

-   Worksheets 9 through 11 display net revenues results for all
    projects and for projects identified by technology (i.e., wind,
    wave, current) and region (i.e., Atlantic, Pacific, Gulf of Mexico).

-   Worksheet 12 presents data necessary to complete the analysis
    required under the Regulatory Flexibility Act (RFA) of 1980, as
    amended by the Small Business Regulatory Enforcement Fairness Act of
    1996 (SBRFA).

Figure A-1 illustrates the basic model structure. Additionally, the
model contains many secondary worksheets used for background
calculations that are not essential for basic use of the model;
accordingly, these worksheets are hidden within the workbook. They can
be uncovered using the Format Sheets Unhide function in Excel.

Model results are of course highly dependent upon the parameter input
values. Comments are attached to each worksheet cell where an
explanation of the basis for a value or set of values is warranted.

**[Financial Parameter Worksheets]{.underline}**

The first three worksheets (General Inputs, Project Inputs, and
Financial Assurance) contain general fiscal information (e.g., interest
rates for debt financing), and more specific, project-level information
(e.g., project year, installed capacity). Any user-based modifications
to general fiscal information, scenario assumptions, project data, or
financial assurance assumptions will occur on these worksheets.
Modifications to electricity price forecasts can be made on the hidden
"FERC Prices" worksheet, which underlies calculation of first-year price
information on the General Inputs worksheet. Each of these worksheets
contains one or more tables, descriptions of which are provided in Table
A-1.

Figure A-1

Structure of Excel-Based Cash Flow Model

![](media/image8.wmf){width="5.394444444444445in"
height="7.138194444444444in"}

Table A-1

Descriptions of Tables in the General Inputs, Project Inputs, and
Financial Assurance Worksheets

+---------+----------------+-------------------------------------------+
| **WORK  | **TABLE**      | **DESCRIPTION**                           |
| SHEET** |                |                                           |
+=========+================+===========================================+
| **      | > Shared       | > Financial parameters shared across all  |
| General | > Parameters   | > projects.                               |
| I       |                |                                           |
| nputs** |                |                                           |
+---------+----------------+-------------------------------------------+
|         | > MMS          | > Fiscal parameters that generate         |
|         | > Scenarios    | > government revenues (e.g., operations   |
|         |                | > fees), based on information from MMS.   |
+---------+----------------+-------------------------------------------+
|         | > PTCs and     | > Production Tax Credit and Renewable     |
|         | > RECs by      | > Energy Certificate values (the latter   |
|         | > Region and   | > based on location and the existence of  |
|         | > Technology   | > a State renewable portfolio standard    |
|         |                | > (RPS)).                                 |
+---------+----------------+-------------------------------------------+
|         | > Electricity  | > Estimated prices for coastal regions of |
|         | > Price: 2007  | > the U.S. from 2007 to 2046, based on    |
|         | > to 2046 by   | > historical information compiled and     |
|         | > Region       | > reported by FERC.                       |
+---------+----------------+-------------------------------------------+
|         | > Capacity     | > Assumed capacity factors for wind,      |
|         | > Factors and  | > wave, and ocean current projects, and   |
|         | > Rated        | > assumed rated capacities for wave and   |
|         | > Capacities   | > ocean current projects included in the  |
|         |                | > development forecast (wind project      |
|         |                | > capacities vary).                       |
+---------+----------------+-------------------------------------------+
|         | > O&M and      | > Baseline installed capital costs,       |
|         | > Installed    | > operations and maintenance costs, and   |
|         | > Capital      | > debt/equity financing share, by         |
|         | > Costs, and   | > technology.                             |
|         | > Debt/Equity  |                                           |
|         | > Financing    |                                           |
|         | > Share        |                                           |
+---------+----------------+-------------------------------------------+
|         | > O&M,         | > Rates at which these parameters are     |
|         | > Installed    | > projected to change based on industry   |
|         | > Capital      | > growth and learning effects.            |
|         | > Costs, and   |                                           |
|         | > Debt         |                                           |
|         | > Financing    |                                           |
|         | > Share        |                                           |
|         | > Adjustments  |                                           |
+---------+----------------+-------------------------------------------+
|         | > 2008 to 2027 | > Using data from the previous two        |
|         | > O&M,         | > tables, forecast of installed capital   |
|         | > Installed    | > costs, operations and maintenance       |
|         | > Capital      | > costs, and debt financing shares for    |
|         | > Costs and    | > each year of the analysis.              |
|         | > Debt         |                                           |
|         | > Financing    |                                           |
+---------+----------------+-------------------------------------------+
| **      | > Project      | > Characteristics of projects as          |
| Project | > Specific     | > specified in the Task 1 report, as      |
| I       | > Parameters   | > amended based on MMS comments. Many of  |
| nputs** |                | > these parameters automatically update   |
|         |                | > based upon user entries and information |
|         |                | > provided in the general inputs          |
|         |                | > worksheet.                              |
+---------+----------------+-------------------------------------------+
|         | > Cash Flow    | > A two-cell table that allows a user to  |
|         | > Sheet        | > quickly observe the cash flow statement |
|         | > Builder      | > for the project and MMS fiscal scenario |
|         |                | > of choice.                              |
+---------+----------------+-------------------------------------------+
| **Fi    | > Bonding      | > Fiscal information on pre-construction, |
| nancial | > Payment      | > operations, and easement                |
| Assu    | > Information  | > decommissioning bonds, as specified by  |
| rance** |                | > MMS.                                    |
+---------+----------------+-------------------------------------------+

These first three worksheets contain parameter values that have been
developed based on research, IEc's professional judgment, and
correspondence with MMS. These parameters can be easily adjusted,
however; model users may enter information common to all projects on the
General Inputs worksheet, information specific to individual projects on
the Project Inputs worksheet, and any new information on financial
assurance and bonding information on the Financial Assurance worksheet.
A separate table in the Project Inputs worksheet allows the model user
to generate the cash flow statement for a particular project and
scenario (selected from pull down menus) using the button labeled Find.

**[Cash Flow and Payments Worksheets]{.underline}**

The Cash Flow worksheet is the centerpiece of the model, as it provides
information on Federal revenues and financial performance associated
with each scenario for projects forecast to begin generating electricity
between 2008 and 2027. The performance component is used to determine
whether a project should be included among those that result in Federal
revenues or costs. The Payments 2028-2036 worksheet incorporates the
assumption that a certain set of projects will begin generating
electricity during this period (rather than modeling specific
hypothetical projects and evaluating their predicted financial
performance). As such, this worksheet estimates only the Federal
revenues associated with those projects (e.g., lease payment or
operating fees collected during the construction period). The scenario
selection cell in this worksheet is linked to the Cash Flow worksheet;
any changes to the scenario -- such as from Baseline to Low -- within
the model should therefore be done using the pull down menu on the Cash
Flow worksheet. If the model user is interested in adjusting how the
model calculates a project's financial performance or the payments it
would make to the Federal government, the structure of the Cash Flow and
Payments 2028-2036 worksheets can be adjusted. There are two ways to
select a particular project and scenario:

-   In the upper left corner of the Cash Flow worksheet, the Project
    Selection and MMS Scenario Selection tables both provide cells with
    pull down menus that allow the project and scenario numbers to be
    selected from a list. To select a project in the 2028 to 2036
    period, select a project number on the Payments 2028-2036 worksheet.
    Adjustment of the scenario on the Cash Flow worksheet will
    automatically adjust the scenario on the Payments 2028-2036
    worksheet.

-   Alternatively, the model user can select the project and scenario
    from a table titled Cash Flow Sheet Builder in the upper right
    corner of the Project Inputs worksheet. In this table, once the user
    has selected the project and scenario numbers, the user can click on
    the Find button, which contains a macro that automatically switches
    to the Cash Flow worksheet and updates the project and scenario
    information according to user selections.

All other cells in the Project Selection, MMS Scenario Selection, and
Financial Assurance tables are simply references to cells in Table 1 of
the Project Inputs worksheet, Table 2 of the General Inputs worksheet,
and/or Table 1 of the Financial Assurance worksheet, respectively.

The remaining tables in the Cash Flow and Payments worksheets include
the following:

-   **Financial Performance and Federal Revenues (Nominal)**, which are
    result summaries for the project currently selected; these outputs
    are described in more detail in the Results section below.

-   **Summary Cash Flow Statement** (only on the Cash Flow worksheet),
    which contains summarized information from the Detailed Cash Flow
    Statement table immediately below. The latter references information
    from the tables at the top of the Cash Flow worksheet (Project
    Selection, MMS Scenario Selection, and Financial Assurance) as well
    as parameter information from the General Inputs worksheet.
    Explanations for each of the calculations are provided in comments
    embedded in the row headers of the detailed cash flow statement. On
    the Payments worksheet, the detailed cash flow statement is labeled
    MMS Payments.

-   **Federal Revenues (Nominal)**. This table is presented to the right
    of the Detailed Cash Flow Statement (or MMS Payment table on the
    Payments 2028-2036 worksheet), and summarizes Federal revenues for
    each year of project operation. If projects do not reach financial
    performance hurdle requirements necessary for inclusion in the
    revenue or cost forecast (described below), this summary table will
    return zero revenues in those years when fees are not paid.
    Information in this table is then transferred to the Revenues
    worksheet.

An Excel macro built into the Cash Flow worksheet (activated using a
button labeled Create Project Sheets) generates individual cash flow and
payments worksheets for the projects forecasted to generate electricity
during the study period (76 projects) and between 2028 and 2036 (27
projects). These 103 worksheets are hidden within the workbook and can
be accessed using another macro button in the Cash Flow worksheet
labeled Unhide Project Sheets. As with the Payments 2028-2036 worksheet,
the MMS scenario for each of these individual project worksheets is
linked to (and therefore changes with) the corresponding scenario pull
down menu in the Cash Flow worksheet. All changes to the scenario should
occur in the Cash Flow worksheet.

**Rerunning the Model**

Since all model calculations are based on these 103 worksheets, if there
are any structural changes to the Cash Flow worksheet (e.g., adjustments
to the schedule of MMS fees under a particular scenario), the cash flow
worksheets need to be regenerated to incorporate these changes, and the
model should be rerun. To regenerate cash flow worksheets, first click
on the Delete Project Sheets button and then on the Create Project
Sheets, both in the Cash Flow worksheet. The latter macro automatically
hides the project worksheets once generated. Steps for rerunning the
model are outlined below (see **Making Changes to the Model**).

**[Financial Performance]{.underline}**

Worksheet 6 contains financial performance information for all projects
under the scenario selected on the Cash Flow worksheet. As the scenario
on the Cash Flow worksheet is adjusted, the values on this worksheet
automatically adjust based on information from the 76 cash flow
worksheets for projects generating electricity between 2008 and 2027.
The most important column on this worksheet is After-Tax IRR, generated
for all scenarios; this is the criterion by which projects are placed
into one of three performance categories: (1) Project Does Not Apply,
where the project does not clear the lower hurdle IRR (currently set at
five percent) and therefore does not submit an application to MMS; (2)
Project Applies but is not Constructed, where the project clears the
lower hurdle rate, but not the upper rate (set at 11 percent) and
therefore applies but is not constructed; and (3) Project is
Constructed, where the project clears the upper rate and is therefore
constructed. The weighted average cost of capital (WACC) -- which is
based on assumed debt and equity interest rates and debt-equity ratios
-- is provided for each project (values range from 10.24 percent to
11.43 percent). Calculation of the WACC is made from the debt financing
rate and the base return on equity rate listed in Table 1 of the General
Inputs worksheet. The cumulative cash flow for each project --
discounted using the project's WACC -- is also provided. This
information is summarized for an individual scenario on the Projects
Exceeding Hurdle Requirements tables in the Performance worksheet. An
Excel macro (a button labeled Generate Performance Table) summarizes the
number of projects clearing each hurdle category for all scenarios and
technologies.

**[Revenue and Cost Results]{.underline}**

Worksheets 7 and 8, Revenues and Costs, contain summaries of Federal
revenues and MMS costs for each of the 103 projects in each year between
2008 and 2027. The Revenues worksheet pulls information from the MMS
Revenues table within the Cash Flow and Payments worksheets and realigns
the data based on the year. The worksheet contains a table at the top of
the page that sums the results for each column to generate the total
annual Federal revenues for all projects under a particular scenario.

The Costs worksheet draws information from three hidden worksheets
(2008-2012 Cost Template, 2013-2027 Cost Template, and Specialties, all
provided by MMS), as well as project performance information from the
Performance worksheet. The full-time equivalent (FTE) information in the
Cost Templates was combined with cost information on the employee
compensation (\"EmplCompenstn\") worksheet provided by MMS (also hidden)
to develop costs in dollars for project-specific (e.g., drafting an EIS)
and non-project-specific (i.e., project management or project
administration) aspects of the program. As project-specific costs are
transferred from the templates to the Costs worksheet, they are aligned
according to the particular year in the Project-Specific Costs table.
Annual non-project-specific costs are summarized in the table Total
Costs for Each Year, which also sums project- and non-project-specific
costs.

Both the Revenues and Costs worksheets contain pivot tables at the
bottom of the worksheets that break down total revenues and costs by
technology and region. Each of these worksheets has an Excel macro
button adjacent to the Total Costs tables labeled Refresh; if any
information in the model is adjusted, the model user should press this
button to refresh the pivot tables with the most recent information.

**[Net Revenues]{.underline}**

Worksheets 9 through 11 summarize the revenue and cost data generated in
earlier worksheets and calculate net revenues (revenues minus costs) in
both nominal and discounted terms. Given the model's construction, it is
impossible to simultaneously calculate the net revenues from multiple
scenarios. Accordingly, an Excel macro on the Results worksheet (with a
button labeled "1. Generate All Results") pages through the scenarios on
the Cash Flow worksheet and pulls resulting information from the hidden
Scenario Results worksheet.[^19] The hidden Scenario Results worksheet,
which draws information from the Revenues and Costs worksheets, reports
the total revenues, costs, and net revenues in nominal and discounted
terms. Discounted revenues are calculated using real rates of three and
seven percent. Worksheets 10 and 11 (\"by Tech\" and \"by Region\")
present the same information as worksheet 9, breaking down the results
by technology and region. Finally, results are presented in report-ready
tables in two hidden worksheets, Report Tables and Report Tables2. These
worksheets are populated using two macros: Generate Report Tables (1)
and Generate Report Tables (2).

**[SBRFA Analysis]{.underline}**

Worksheet 12 generates comparisons of individual projects\' costs (i.e.,
payments to the Federal government) to the forecast of revenues that the
project will generate through electricity sales and renewable energy
certificate sales (as appropriate) for the Most Likely scenario. An
Excel macro (with an associated button labeled Run SBRFA Analysis) calls
on the individual Cash Flow worksheets to generate the necessary
information for each project in the development forecast, using two
hidden worksheets in the process: SBRFA_temp and SBRFA_data.

**[Making Changes to the Model]{.underline}**

The model user may also wish to make additional changes to the model,
which requires that the model be rerun to create new results. To rerun
the model, follow these steps:

> Step 1: On the Cash Flow worksheet, click the Delete Project Sheets
> button followed by the Create Project Sheets button to regenerate the
> cash flow worksheets (note that the latter macro automatically hides
> the 103 project worksheets once generated);
>
> Step 2: On the Performance worksheet, click the Generate Performance
> Data button to regenerate performance results; and
>
> Step 3: On the Results worksheet, click, sequentially, the buttons
> labeled "1. Generate All Results", "2.Generate Report Tables (1)", and
> "3. Generate Report Tables (2)." This will regenerate the same
> variations on the analytical results that are included in the body of
> this report.

Three particular examples of modifications to the model are described in
more detail below.

**Adjustment of fiscal terms.** The user may wish to adjust the fees
associated with lease issuance, pre-production rentals, operation, or
project easement for one or more of the scenarios. These fees can be
found in Table 2 (cells C22 to L26) of the General Inputs worksheet (one
row corresponds to each of the four MMS scenarios and one additional row
to the Intermediate-No REC scenario). Note that as the values in Table 2
of the General Inputs worksheet are adjusted, cells C6 to L6 on the Cash
Flow worksheet (with the appropriate scenario selected) update
automatically. The fees can be adjusted on the General Inputs worksheet
as follows:

-   The per acre lease issuance fee (cells C22 to C26) and the project
    easement rental fee (cells L22 to L26) are straightforward to
    adjust: simply change the values in these cells from their currently
    assigned values (e.g., \$0.25 per acre and \$5 per acre under the
    Intermediate scenario) to new values and rerun the model by
    following Steps 2 and 3 above (when making this adjustment, the cash
    flow worksheets update automatically, so Step 1 is unnecessary).

-   The per acre pre-production rental fee occupies three columns of
    cells on the General Inputs worksheet (cells D22 through F26)
    corresponding to three fee levels that occur over sub-periods within
    the seven-year pre-production period: the first level occurs in
    years one and two (cells D22 to D26); the second in years three and
    four (cells E22 to E26); and the final level in years five through
    seven (cells F22 to F26; under the High payment case these fee
    levels are \$3 per acre, \$4 per acre, and \$5 per acre,
    respectively).[^20] Once the user has developed an alternate set of
    fees corresponding to the three fixed sub-periods, these can simply
    be entered into cells D22 through F26 and the model can be rerun.
    Note that in the Low payment case, the fee contained in cells F22 to
    F26 (i.e., corresponding to the third sub-period) serves as a
    substitute for the operating fee and occurs over the entire
    operating period.

-   The operating fee is contained within cells G22 through K26 and is
    similar to the pre-production rental fee in that different fee
    levels occur over the construction and operations period. Rather
    than a per acre fee, the operating fee is a percentage of a
    capacity-based projection of electricity revenues (as displayed in
    these cells). The first fee level (cells G22 to G26) occurs in the
    two years following initiation of project construction (see the note
    in Table 4-7); the second (cells H22 to H26) occurs until year eight
    of electricity generation (i.e., if project construction lasts one
    year, the construction fee extends through the first year of
    electricity generation, so this second fee extends an additional six
    years); the third fee level (cells I22 to I26) occurs over the next
    seven years (to year 15 of electricity generation); and the fourth
    level (cells J22 to J26) occurs over the final five years of project
    operation.[^21] The user can enter new fees corresponding to these
    four fixed sub-periods into cells G22 through K26 and can then rerun
    the model. Under the High scenario only, the user also has the
    option of levying, in the last five years of project operation, an
    additional fee calculated as a percentage of a project\'s renewable
    electricity credit (REC) revenues or production tax credits (PTCs)
    (cells K22 to K26). If interested in evaluating the effects of such
    a fee, the user must first select the High scenario and then adjust
    one or more of the cells between K22 and K26.

**Modification of project characteristics or the project schedule.** The
user may also wish to reduce the number of projects being evaluated or
to modify the characteristics of particular projects.[^22]^,^[^23] To
reduce the number of projects being evaluated, the user should first
select which projects will be removed from the list of 103 projects on
the Project Inputs worksheet. Next, simply enter a letter, such as "A",
after the project number contained in the cells down column A. For
example, if the user were interested in no longer including project 1 in
the forecast, simply change "1" in cell A5 to "1A". This preserves the
characteristics of the project while making it unrecognizable to the
performance and results macros. The user can now develop new output
tables, by rerunning these macros.

The characteristics of particular projects can be changed in two ways:
by modifying the information on the General Inputs worksheet, which
influences groups of projects on the Project Inputs worksheet
automatically; or by directly changing project information on the
Project Inputs worksheet. Note that the latter approach eliminates the
reference formulas in the modified Project Inputs cells, such that
changes to the previously referenced cells (e.g., on the General Inputs
worksheet) will no longer update these project characteristics. Once the
user has modified project characteristics using one (or both) of these
approaches, rerun the model as described above (Steps 1, 2, and 3).

**No-PTC Scenario.** Appendix D reports project performance assuming
that the PTC is not available to any projects in the 2008 to 2027 period
of analysis. The user may be interested in more detailed information on
this scenario, such as net revenues by technology or region. Cell K2 on
the Project Inputs worksheet contains a pull down menu with either \$0
or \$0.02 (per kilowatt-hour), where \$0 corresponds to the no-PTC
scenario and \$0.02 corresponds to the with-PTC scenario. Developing the
output from the no-PTC scenario is straightforward: simply adjust this
pull down menu and rerun the model as described above (Steps 2 and 3
only).

**APPENDIX B PROJECT FINANCIAL INFORMATION**

Table B-1

Forecasted Electricity Production and Financial Performance Information
for Projects Operational by 2027

  ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
  **Startup   **Location**   **Technology**   **Capacity   **Rated    **Annual      **Production   **Project    **Weighted   **Discounted   **Project IRR                               
  Year**                                      Factor**     Plant      Electricity   Before 2027    Lifetime     Average Cost Cash Flow:     by Payment                                  
                                                           Capacity   Production    (MWH)**        Production   of Capital** Intermediate   Case**                                      
                                                           (MW)**     (MWH)**                      (MWH)**                   Payment Case                                               
                                                                                                                             (Millions)**                                               
  ----------- -------------- ---------------- ------------ ---------- ------------- -------------- ------------ ------------ -------------- -------------- --------- ------------------ ----------
                                                                                                                                            **Baseline**   **Low**   **Intermediate**   **High**

  **2013**    New England    Wind             0.38         500        1,665,540     24,983,100     33,310,800   10.24%       \$448.2        25.26%         25.25%    24.92%             24.62%

              New York       Wind             0.38         150        499,662       7,494,930      9,993,240    10.24%       \$37.2         15.75%         15.74%    15.30%             14.73%

  **2017**    Mid-Atlantic   Wind             0.38         150        499,662       5,496,282      9,993,240    10.88%       -\$19.6        8.80%          8.78%     8.24%              7.42%

              Mid-Atlantic   Wind             0.38         500        1,665,540     18,320,940     33,310,800   10.88%       \$61.1         12.68%         12.66%    12.16%             11.56%

              Mid-Atlantic   Wind             0.38         150        499,662       5,496,282      9,993,240    10.88%       -\$19.6        8.80%          8.78%     8.24%              7.42%

              New England    Wind             0.38         500        1,665,540     18,320,940     33,310,800   10.88%       \$513.4        25.28%         25.27%    24.98%             24.71%

              New England    Wind             0.38         150        499,662       5,496,282      9,993,240    10.88%       \$116.0        23.18%         23.16%    22.86%             22.56%

  **2018**    Mid-Atlantic   Wind             0.38         500        1,665,540     16,655,400     33,310,800   10.88%       \$64.5         12.77%         12.75%    12.25%             11.64%

              New England    Wind             0.38         500        1,665,540     16,655,400     33,310,800   10.88%       \$525.3        25.35%         25.34%    25.04%             24.78%

              New York       Wind             0.38         150        499,662       4,996,620      9,993,240    10.88%       \$62.4         18.11%         18.10%    17.73%             17.32%

              New York       Wind             0.38         500        1,665,540     16,655,400     33,310,800   10.88%       \$337.1        20.84%         20.83%    20.47%             20.12%

              Southeast      Wind             0.38         150        499,662       4,996,620      9,993,240    10.88%       -\$89.3        -4.77%         -4.80%    -5.66%             -7.92%

              California     Wave             0.35         75         230,108       2,301,075      4,602,150    10.88%       -\$40.5        -7.39%         -7.50%    -8.71%             -12.87%

              California     Wave             0.35         75         230,108       2,301,075      4,602,150    10.88%       -\$40.5        -7.39%         -7.50%    -8.71%             -12.87%

              Oregon         Wave             0.35         75         230,108       2,301,075      4,602,150    10.88%       -\$48.1        -14.34%        -14.44%   -15.73%            -20.85%

              Oregon         Wave             0.35         75         230,108       2,301,075      4,602,150    10.88%       -\$48.1        -14.34%        -14.44%   -15.73%            -20.85%

  **2019**    Mid-Atlantic   Wind             0.38         150        499,662       4,496,958      9,993,240    10.88%       \$15.9         13.58%         13.56%    13.05%             12.44%

              Mid-Atlantic   Wind             0.38         150        499,662       4,496,958      9,993,240    10.88%       \$15.9         13.58%         13.56%    13.05%             12.44%

              Mid-Atlantic   Wind             0.38         500        1,665,540     14,989,860     33,310,800   10.88%       \$152.2        16.16%         16.14%    15.66%             15.17%

              New England    Wind             0.38         500        1,665,540     14,989,860     33,310,800   10.88%       \$621.7        28.69%         28.68%    28.37%             28.13%

              Southeast      Wind             0.38         150        499,662       4,496,958      9,993,240    10.88%       -\$55.5        1.34%          1.30%     0.56%              -1.00%

              California     Wind             0.38         150        499,662       4,496,958      9,993,240    10.88%       -\$20.8        8.23%          8.20%     7.66%              6.80%

  **2019      California     Wind             0.38         150        499,662       4,496,958      9,993,240    10.88%       -\$20.8        8.23%          8.20%     7.66%              6.80%
  (cont.)**                                                                                                                                                                             

              Florida        Current          0.8          30         210,384       1,893,456      4,207,680    10.88%       \$56.0         54.31%         54.24%    53.60%             53.29%

              Florida        Current          0.8          30         210,384       1,893,456      4,207,680    10.88%       \$56.0         54.31%         54.24%    53.60%             53.29%

              Florida        Current          0.8          30         210,384       1,893,456      4,207,680    10.88%       \$56.0         54.31%         54.24%    53.60%             53.29%

              Florida        Current          0.8          30         210,384       1,893,456      4,207,680    10.88%       \$56.0         54.31%         54.24%    53.60%             53.29%

              Florida        Current          0.8          30         210,384       1,893,456      4,207,680    10.88%       \$56.0         54.31%         54.24%    53.60%             53.29%

              Florida        Current          0.8          30         210,384       1,893,456      4,207,680    10.88%       \$56.0         54.31%         54.24%    53.60%             53.29%

  **2020**    Mid-Atlantic   Wind             0.38         150        499,662       3,997,296      9,993,240    10.88%       \$16.9         13.67%         13.65%    13.14%             12.53%

              Mid-Atlantic   Wind             0.38         500        1,665,540     13,324,320     33,310,800   10.88%       \$157.4        16.24%         16.23%    15.75%             15.25%

              New England    Wind             0.38         500        1,665,540     13,324,320     33,310,800   10.88%       \$635.6        28.75%         28.74%    28.44%             28.20%

              New England    Wind             0.38         500        1,665,540     13,324,320     33,310,800   10.88%       \$635.6        28.75%         28.74%    28.44%             28.20%

              New York       Wind             0.38         1,000      3,331,080     26,648,640     66,621,600   10.88%       \$1,212.4      29.20%         29.18%    28.84%             28.59%

              New York       Wind             0.38         500        1,665,540     13,324,320     33,310,800   10.88%       \$440.4        24.18%         24.17%    23.81%             23.50%

              Gulf of Mexico Wind             0.38         150        499,662       3,997,296      9,993,240    10.88%       -\$49.2        3.01%          2.98%     2.28%              0.92%

              Oregon         Wave             0.35         75         230,108       1,840,860      4,602,150    10.88%       -\$30.3        -2.62%         -2.72%    -3.76%             -6.92%

              Oregon         Wave             0.35         75         230,108       1,840,860      4,602,150    10.88%       -\$30.3        -2.62%         -2.72%    -3.76%             -6.92%

              Florida        Current          0.8          30         210,384       1,683,072      4,207,680    10.88%       \$57.3         54.50%         54.43%    53.79%             53.48%

              Florida        Current          0.8          30         210,384       1,683,072      4,207,680    10.88%       \$57.3         54.50%         54.43%    53.79%             53.48%

              Florida        Current          0.8          30         210,384       1,683,072      4,207,680    10.88%       \$57.3         54.50%         54.43%    53.79%             53.48%

  **2021**    Mid-Atlantic   Wind             0.38         150        499,662       3,497,634      9,993,240    10.88%       \$17.9         13.75%         13.74%    13.23%             12.62%

              Mid-Atlantic   Wind             0.38         500        1,665,540     11,658,780     33,310,800   10.88%       \$162.5        16.32%         16.31%    15.83%             15.33%

              Southeast      Wind             0.38         150        499,662       3,497,634      9,993,240    10.88%       -\$56.7        1.49%          1.46%     0.71%              -0.84%

              Southeast      Wind             0.38         1,000      3,331,080     23,317,560     66,621,600   10.88%       \$167.0        13.49%         13.47%    12.96%             12.39%

              California     Wind             0.38         500        1,665,540     11,658,780     33,310,800   10.88%       \$34.7         11.71%         11.69%    11.20%             10.57%

              California     Wind             0.38         500        1,665,540     11,658,780     33,310,800   10.88%       \$34.7         11.71%         11.69%    11.20%             10.57%

              California     Wind             0.38         500        1,665,540     11,658,780     33,310,800   10.88%       \$34.7         11.71%         11.69%    11.20%             10.57%

              California     Wind             0.38         1,000      3,331,080     23,317,560     66,621,600   10.88%       \$407.6        18.11%         18.09%    17.65%             17.24%

  **2021      Washington     Wave             0.35         75         230,108       1,610,753      4,602,150    10.88%       -\$30.7        -2.54%         -2.64%    -3.68%             -6.84%
  (cont.)**                                                                                                                                                                             

              Oregon         Wave             0.35         75         230,108       1,610,753      4,602,150    10.88%       -\$30.7        -2.54%         -2.64%    -3.68%             -6.84%

              California     Wave             0.35         75         230,108       1,610,753      4,602,150    10.88%       -\$22.4        2.56%          2.49%     1.65%              -0.28%

              Florida        Current          0.8          30         210,384       1,472,688      4,207,680    10.88%       \$58.6         54.69%         54.63%    53.99%             53.67%

              Florida        Current          0.8          30         210,384       1,472,688      4,207,680    10.88%       \$58.6         54.69%         54.63%    53.99%             53.67%

  **2022**    Mid-Atlantic   Wind             0.38         500        1,665,540     9,993,240      33,310,800   11.43%       \$127.1        14.90%         14.88%    14.45%             13.98%

              New England    Wind             0.38         500        1,665,540     9,993,240      33,310,800   11.43%       \$602.6        26.18%         26.17%    25.89%             25.65%

              New England    Wind             0.38         150        499,662       2,997,972      9,993,240    11.43%       \$148.5        25.31%         25.30%    25.02%             24.76%

              New York       Wind             0.38         1,000      3,331,080     19,986,480     66,621,600   11.43%       \$1,167.1      26.79%         26.77%    26.45%             26.20%

              Florida        Current          0.8          30         210,384       1,262,304      4,207,680    11.43%       \$56.1         48.95%         48.89%    48.30%             48.00%

              Florida        Current          0.8          30         210,384       1,262,304      4,207,680    11.43%       \$56.1         48.95%         48.89%    48.30%             48.00%

              Florida        Current          0.8          30         210,384       1,262,304      4,207,680    11.43%       \$56.1         48.95%         48.89%    48.30%             48.00%

  **2023**    New England    Wind             0.38         1,000      3,331,080     16,655,400     66,621,600   11.43%       \$1,679.6      32.73%         32.72%    32.45%             32.25%

              Gulf of Mexico Wind             0.38         500        1,665,540     8,327,700      33,310,800   11.43%       -\$12.6        10.20%         10.18%    9.69%              9.07%

              Gulf of Mexico Wind             0.38         1,000      3,331,080     16,655,400     66,621,600   11.43%       \$262.1        15.31%         15.29%    14.85%             14.41%

  **2024**    New England    Wind             0.38         1,000      3,331,080     13,324,320     66,621,600   11.43%       \$1,714.2      32.78%         32.77%    32.49%             32.29%

              New England    Wind             0.38         500        1,665,540     6,662,160      33,310,800   11.43%       \$711.0        29.50%         29.50%    29.20%             28.98%

              Mid-Atlantic   Wind             0.38         500        1,665,540     6,662,160      33,310,800   11.43%       \$217.4        17.96%         17.95%    17.51%             17.10%

  **2025**    Mid-Atlantic   Wind             0.38         500        1,665,540     4,996,620      33,310,800   11.43%       \$222.4        17.99%         17.98%    17.54%             17.13%

              Mid-Atlantic   Wind             0.38         1,000      3,331,080     9,993,240      66,621,600   11.43%       \$742.5        22.23%         22.22%    21.81%             21.47%

              California     Wind             0.38         500        1,665,540     4,996,620      33,310,800   11.43%       \$89.3         13.93%         13.91%    13.49%             13.01%

  **2026**    California     Wind             0.38         1,000      3,331,080     6,662,160      66,621,600   11.43%       \$486.7        18.59%         18.58%    18.18%             17.82%

              California     Wind             0.38         1,000      3,331,080     6,662,160      66,621,600   11.43%       \$486.7        18.59%         18.58%    18.18%             17.82%

              California     Wind             0.38         1,000      3,331,080     6,662,160      66,621,600   11.43%       \$486.7        18.59%         18.58%    18.18%             17.82%

  **2027**    Mid-Atlantic   Wind             0.38         1,000      3,331,080     3,331,080      66,621,600   11.43%       \$773.9        22.28%         22.27%    21.86%             21.52%

              Southeast      Wind             0.38         1,000      3,331,080     3,331,080      66,621,600   11.43%       \$237.9        14.54%         14.53%    14.08%             13.62%

              Florida        Current          0.8          60         420,768       420,768        8,415,360    11.43%       \$136.2        54.66%         54.63%    53.99%             53.70%
  ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

![](media/image9.png){width="0.9694444444444444in"
height="0.9263888888888889in"}

![](media/image10.png){width="1.0in" height="1.0in"}

[^1]: The EPAct requires distribution of 27 percent of revenue from any
    qualified alternative energy/alternate use project, to be shared
    among eligible States.

[^2]: The effects of transfer payments typically are ignored in national
    cost-benefit equations, because they tend not to create any net
    costs or benefits to society on their own; the recipients' gains are
    offset by the costs to the payers.

[^3]: This difference would increase beyond the period of analysis, when
    the later years of operation for each project occur. For the High
    case, the later years also would include the higher net benefits
    produced by the graduated operating fee rate.

[^4]: It is possible that the proposed rule may eventually govern
    hydrogen production, affecting entities that fall under NAICS Code
    325120, Industrial Gas Manufacturing. However, it is unlikely that
    hydrogen will be produced on the OCS in significant amounts during
    the 20-year period of analysis, and MMS has no means to predict what
    kinds of entities would likely be involved in hydrogen production,
    given the lack of proposals for projects that would produce
    hydrogen.

[^5]: National Energy Policy: Report of the National Energy Policy
    Development Group, May 2001; Advanced Energy Initiative, National
    Economic Council, February 2006.

[^6]: Existing MMS regulations for offshore activities apply
    specifically to oil and natural gas activities or to other minerals;
    these existing regulations could not accommodate alternative energy
    and alternate uses of the OCS.

[^7]: Executive Order 12866, Regulatory Planning and Review, September
    30, 1993, Section 3(f). This text was unchanged by the recent
    amendments to the Executive Order. See Executive Order: Further
    Amendment to Executive Order 12866 on Regulatory Planning and
    Review, as viewed at
    <http://www.whitehouse.gov/news/releases/2007/01/print/20070118.html>
    on May 24, 2007.

[^8]: We note one possible exception to this assumption. The timing of
    some projects is subject to a single assumed lease sale which, in
    the MMS alternative, occurs in 2012. In the baseline case no lease
    sale occurs and the Corps and FERC would have considered
    applications on a rolling basis. In the MMS alternative, as soon as
    MMS begins to receive expressions of interest in overlapping
    geographical areas, the agency would delineate the areas subject to
    competition through one or more lease sales. For this analysis,
    therefore, the applications for projects within the area subject to
    competition would not be accepted until after the lease sale in
    2012. However, given the lack of legal and regulatory certainty
    inherent in the baseline, many investors and lenders might have
    withheld funding until more certainty regarding regulatory, legal,
    and economic risk was established by a few early projects.
    Therefore, it is not at all certain that the baseline scenario would
    have differed substantially from the one underlying the MMS
    alternative.

[^9]: As with wind energy, technology and resource considerations will
    influence project-specific capacity factors.

[^10]: Note that capital cost data for both wind and wave power were
    collected in 2007 and are therefore presented in 2007 dollars.

[^11]: The data provided to us focus on the review of alternative energy
    projects proposed for the OCS. Since we do not have separate
    information that describes the anticipated level of effort
    associated with review of projects that involve alternate uses of
    existing facilities, our estimate does not include the Federal
    government\'s anticipated costs to review these proposed activities.
    We expect that these costs will be significantly lower than the
    costs associated with alternative energy projects (based on the
    assumption that the overall level of activity involving alternate
    uses will be relatively low during the period of analysis).
    Nevertheless, exclusion of these costs results in an understatement
    of estimated total program costs.

[^12]: At the time this report was completed, it appeared likely that
    the MMS inspection program would be more rigorous than originally
    assumed. However, given that no formal decisions have been made in
    this regard and that the specifics of the program remain unclear,
    the MMS costs do not include the additional spending that might be
    required.

[^13]: In April 2008, the U.S. Senate approved, as part of H.R.3221 --
    "Foreclosure Prevention Act of 2008", an extension of the Federal
    production tax credit through January 1, 2010, that would make the
    tax credit available for marine hydrokinetic technologies, including
    wave, current, and tidal energy.   A similar bill is currently under
    consideration in the House of Representatives.  While there remains
    uncertainty that this bill will be enacted, it is not unreasonable
    to assume that future Congressional action will expand and extend
    the tax credit.

    .

[^14]: The three projects in question are hypothetically placed in the
    California market with electricity production beginning in 2021. The
    calculated IRR is marginally below the 11 percent threshold at
    approximately 10.6 percent. In comparison, an identically sized
    project in the Mid-Atlantic region that hypothetically begins
    operation in the same year has an IRR over 15 percent in the High
    case. Since the model assumes the same REC price for both regions,
    the difference in IRR is explained solely by difference in projected
    electricity prices (which are generally lower in California).

[^15]:

[^16]: Crystal Ball Version 7.2.2, Decisioneering, Inc., Denver,
    Colorado.

[^17]: Due to rounding, the present value cumulative net revenue
    subtotals by technology and by region for each case do not sum to
    the overall present value cumulative net revenue totals.

[^18]: SBA, Office of Advocacy, "A Guide for Government Agencies: How to
    Comply with the Regulatory Flexibility Act, Implementing the
    President's Small Business Agenda and Executive Order 13272," May
    2003.

[^19]: Note that the steps for rerunning the model and regenerating the
    results are outlined in the **Making Changes to the Model** section
    below.

[^20]: The model is not currently constructed to allow adjustments in
    the timing of changes in the rental fee levels (e.g., allowing the
    first level to occur in years one through three rather than years
    one and two). To make such an adjustment, the user would need to
    modify the conditional reference formulas contained in cells D50 to
    AD53 in the Cash Flow worksheet.

[^21]: Here too, the model is not currently constructed to allow
    adjustments in the timing of changes in the operating fee levels.

[^22]: Because these steps involve making changes to the Project Inputs
    worksheet (and possibly the General Inputs worksheet), the user may
    want to make these changes in a separate copy of the model to ensure
    that none of the original project information is lost.

[^23]: Increasing the number of projects in the schedule is a more
    complex modeling exercise and is not discussed in this Appendix.