A. I have held leadership positions in both the private and public sectors including Chief Financial Officer for a power plant

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1 DIRECT TESTOMONY OF FRANCIS HODSOLL ON BEHALF OF THE MARYLAND DC VIRGINIA SOLAR ENERGY INDUSTRIES ASSOCIATION BEFORE THE STATE CORPORATION COMMISSIN OF VIRGINIA CASE NO. PUE Q. Please state your name and business address. A. My name is Francis Hodsoll. My business address is 1261 Wild Hawthorn Way, Reston, VA Q. By whom are you employed and in what capacity? A. I am the President of E&E Frontiers, an energy consulting and infrastructure development company. Q. Please describe your experience and qualifications. A. I have held leadership positions in both the private and public sectors including Chief Financial Officer for a power plant owner and operator;; Vice President running a division that provided outsourced wholesale operations to electric utilities;; Deputy Director of the Federal Regulator for Offshore Energy;; and Vice President in charge of a distributed energy project development group. I have an MBA from the MIT Sloan School of Management and a BA in Economics from Colby College. Q. Have you previously testified before the State Corporation Commission of Virginia (the Commission )?

2 A. Yes, PUE , in which Virginia Electric and Power Company (the Company ) sought approval of a solar standby charge for residential systems greater than ten (10) kilowatts capacity. Q. On whose behalf are you submitting testimony? A. I am submitting testimony on behalf of the Maryland DC Virginia Solar Energy Industries Association ( MDV-SEIA ). Q. How are you involved with MDV-SEIA? A. I am a member of the Board of Directors and the Executive Committee, serving as MDV-SEIA s Treasurer. 2

3 Q. Please describe MDV-SEIA. A. MDV-SEIA s mission is to protect and grow the regional solar market by advocating for pro-solar policies. MDV-SEIA also provides general education sessions to the public, works constructively with permitting, zoning, and fire code officials, among others, to ensure that the industry is complying with codes and standards. MDV-SEIA currently has more than 140 members in the region, equating to more than 5,000 jobs according to a 2013 study performed by the Solar Foundation. These members work in all areas of the solar industry, including manufacturers, installers, professional service organizations, individuals and other entities with connections to the solar industry. Q. What is the purpose of your testimony in this proceeding? A. MDV-SEIA has an interest in this proceeding to provide the Commission data and analysis demonstrating that the ratepayer would benefit from third-party competition in the development and ownership of solar generating facilities, such as the Remington facility. MDV-SEIA believes that the Commission should institute a process to maximize the deployment of the maximum number of solar projects in Virginia prior to the expiration of the 30% federal investment tax credit (the ITC ) in 3

4 2016. Otherwise, there is the risk of losing full utilization of the 30% ITC and driving up the cost of solar generation in Virginia. Q. Have there been any recent legislative developments affecting the solar industry in Virginia that impact this proceeding? A. In both HB 2237 and SB 1349, the 2015 Virginia General Assembly determined that [t]he construction or purchase by a utility of one or more generation facilities with at least one megawatt of generating capacity, and with an aggregate rated capacity that does not exceed 500 megawatts, that use energy derived from sunlight and are located in the Commonwealth, regardless of whether any of such facilities are located within or without the utility's service territory, is in the public interest, and in determining whether to approve such facility, the Commission shall liberally construe the provisions of this title. Given the General Assembly s policy, the question before the Commission, as first being raised here, is how to deploy solar efficiently and in the public interest in Virginia. The key issues facing the Commission include: 1. Minimize the Levelized Cost of Energy ( LCOE ) to the ratepayer;; 2. Minimize risks to the ratepayer;; and 4

5 3. Maximize the utilization of the federal ITC by bringing online as much solar as possible by December 31, 2016, subject to the maximum 500 MWs. Q. Please provide your conclusions about the proposed project. A. In reviewing the proposed Remington project, the Company has failed to adequately assess third-party options. The Company claims that the capital costs are competitive;; however, only competitive transparent procurement processes can determine whether the Company received the most competitive capital costs. Fortunately, the EPC market for solar is very competitive and the key issues are not the availability of capital, but rather the ability for third-party financed projects to utilize significantly lower cost of capital and the ability for third-party financed projects to pass the impact of such tax benefits through to the ratepayer in the form of lower costs. Q. Are there key issues in solar project development that impact the cost to a utility s ratepayers? The two (2) key issues impacting the cost to the ratepayer are (1) how the tax benefits are treated in calculating the cost to the ratepayer and (2) the cost of capital or required returns. As I discuss in more detail later in my testimony, as a rate-based asset, the Company normalizes the tax benefits over the life of the project. In contrast, a third-party financed project would account for the tax benefits up front - the ITC would provide a cash flow benefit essentially immediately upon commercial 5

6 operations and would utilize the five-year Modified Accelerated Cost Recovery System (the MACRS ) tax depreciation benefits over the first five (5) years of the project. The highly competitive nature of solar project development results in the full value of these tax benefits passed through in the pricing of the power. In addition to higher levelized costs and much higher upfront ratepayer impacts, the ratepayer bears the performance risks. A 1 third-party financed project would enter into a standard power purchase agreement (a PPA ), which often include liquidated damages for failure to provide the contracted energy within certain parameters that are negotiated in these contracts. This means that the third-party PPA is not only better from a ratepayer risk perspective, but it also creates a stronger incentive for the project owner to ensure high performance. Q. How does the treatment of Solar Renewable Energy Credits ( SRECs ) affect your analysis? A. In proposing a rate-based cost structure in this proceeding, the Company has assumed the sale of the SRECs. If the Company sells these SRECs outside of Virginia, Remington will not count toward Virginia s compliance with federal Clean Power Plan, as currently envisioned. Further, the ratepayer will bear the market risk of the SRECs if the project is rate based. As provided in the Company s application, $1.5 million in value to the ratepayer per year is assumed through the sale of SRECs. This 1 Power Purchase Agreement is the contractual relationship between a party who sells electricity and the party who is buying the electricity. 6

7 assumes stable SREC pricing in Pennsylvania and that the Pennsylvania market remains open to Virginia projects. The history of these markets for SREC sales demonstrates that states often restrict the sale of outside SRECs into their market in order to maximize the in-state economic development. 7

8 Q. Please provide examples of pricing for third-party financed projects. A. According to GTM Research s recently rolled-out U.S. Utility PPA Price Tracker, the first half of 2014 has seen utility-scale 2 solar command PPA prices between $50 per megawatt-hour and $75 per megawatt-hour. One example is First Wind in Utah. By offering solar projects to Rocky Mountain Power at prices below that of natural gas generation, the utility procured four (4) 80 megawatt PPAs. Louisville Gas and Electric in Kentucky recently issued an RFP for ten (10) megawatts of utility-scale solar;; and Xcel Energy in Minnesota procured 100 megawatts of utility-scale solar in an integrated resource plan ( IRP ), among other examples. As shown in Figure 1, there are also more than four (4) gigawatts of operating projects that have PPA prices above $80 per megawatt-hour, while less than one (1) gigawatt of projects in development have PPA prices above this price. This indicates that it is currently a favorable time to acquire projects

9 Figure 1 9

10 Q. Would third-party alternatives offer other benefits? A. Another benefit of third-party financing that the Company should consider is that the site evaluation and selection processes can be eliminated or significantly reduced by soliciting shovel-ready or already constructed projects in Virginia. In reviewing the Pre-filed Direct Testimony of Company Witness Mark D. Mitchell, dated January 20, 2015 in Case No. PUE and pages 4-6 of 218 of Filing Schedule 46B, Statement I, it is evident that the Company must deploy significant resources to narrow and eventually select a preferred site. In comparison, if solar developers - who already have a pipeline of projects - were able to submit proposals, the Company could eliminate much of the expense directed toward Primary Criteria (land, interconnection, and environmental permitting and compliance). Instead, the Company could focus on step 2, narrowing the process among potential sites. Q. Please explain how a third-party project can provide lower capital cost. 10

11 A. Compared to the Company s ten percent (10%) allowed rate of return, the competitive market is buying projects for 6-7% 3 unlevered after-tax Internal Rate of Return (IRR) for large utility-scale. As an example, SunEdison acquired a portfolio from 4 Capital Dynamics for a levered 9% yield. The competitive generation market has moved to a YieldCo model. These financing structures bid significantly lower cost of capital for projects than seen several years ago. As explained by NREL s Renewable Energy Project Finance Journal: A YieldCo is a dividend growth-oriented public company, created by a parent company (e.g., SunEdison), that bundles renewable and/or conventional long-term contracted operating assets in order to generate predictable cash flows. YieldCos allocate cash available for distribution (CAFD) each year or quarter to shareholders in the form of dividends. This investment can be attractive to shareholders because they can expect low-risk returns (or yields) that are projected to increase over time. The capital raised can be used to pay off expensive debt or finance new projects at rates lower than those available through tax equity finance, which can exceed 8%. 3 The Internal Rate of Return on an investment or project is the "annualized effective compounded return rate" or rate of return that makes the net present value of all cash flows (both positive and negative) from a particular investment equal to zero. It can also be defined as the discount rate at which the present value of all future cash flow is equal to the initial investment or in other words the rate at which an investment breaks even

12 The case for YieldCos can be compelling, especially as an alternative to master limited partnerships (MLPs) and real estate investment trusts (REITs). YieldCos, sometimes referred to as "synthetic MLPs," are structured to simulate the avoided double-taxation benefit of MLPs and REITs. This means that rather than taxation taking place twice (once at the corporate level and again at the shareholder level), the yieldco is able to pass its untaxed earnings through to 5 investors. This is achieved by matching strong positive cash flows (income from assets) with losses that exceed taxable income (losses due to renewable asset depreciation and expenses). These "net operating losses" reduce the company's taxable income so that the company is taxed on lower annual earnings, or may not even owe taxes at all. Net operating losses can "carry forward" for future taxable events and therefore, many yieldcos do not expect to pay significant income tax for a period of years. Additionally, dividends may also receive favorable tax treatment at the shareholder level if the returns are treated as return of the original investment, as opposed to return on investment. 6 When earnings are taxed at only one level, the company is able to raise capital from shareholders more affordably. Class A Common Stock shareholders typically receive a 1099-DIV form for tax purposes, rather than the K-1 form associated with MLPs. 5 Porter, L., Hurley, P., Bradley, D. (2013). "Alternative Investment Structures." Navigant. Accessed July 29, 2013: 6 Martin, K. (December 2013). "Yield Cos Compared." Chadbourne & Parke LLP. 12

13 California solar procurement experience between 2009 and 2012 demonstrates that utility rate-based solar was much more expensive than the comparable third-party owned projects. PG&E and SCE had programs to procure several hundred MW of PV, half utility-owned;; half third-party owned. Midway in the program, the utility-owned portions were cancelled due to the superior economics of the third-party projects. Aside from internal inefficiencies, utility rate based projects are disadvantaged by tax normalization rules that prevent them from immediately passing through the ITC and other tax benefits to the utility customer. California produces a legislative report that shows the cost of utility renewables, demonstrating that utility owned 7 solar projects have generally been higher than the third-party owned. Q. Please describe what you mean by normalization. A. Normalization creates interperiod allocation of the income tax effects of accelerated depreciation deductions, the ITC and the alternative minimum tax for regulatory rate-making purposes. "Normalization" involves: (1) setting up a deferred tax reserve for the difference between depreciation expense used by regulators to determine cost of service (normally the straight line method) and the accelerated method used for calculating tax expense on income tax returns and then (2) drawing down that

14 reserve in later years as the accelerated depreciation benefits reverse. Normalization protects the utility s revenues from the effects of lower rates due to accelerated depreciation. Q. Why does normalization result in a higher cost to the ratepayer? 8 A. Normalization results in higher costs to the ratepayer in the near term, and the Net Present Value (NPV) of the costs will also be greater. All current and future ratepayers pay higher costs. Normalization has two options for the federal ITC. Under the option utilized by Dominion, the federal ITC is amortized over the life of the project and the amortization expense is applied each period to the tax of the project. This results in a lower required dollar return on the rate base to achieve the same after tax allowed percent return on the rate base. However, because the benefit is spread out over the life of the project rather than utilized up front, the ratepayer loses the time value of money. Further, for rate-making purposes the company depreciates the project over the life of the project rather than utilizing the 9 five-year MACRS. The company then determines the difference between the accumulated depreciation under the project s 8 The difference between the present value of cash inflows and the present value of cash outflows. NPV is used in capital budgeting to analyze the profitability of an investment or project. NPV=n=0NCn(1=r)n- C0 Where: Cn = net cash inflow during the period;; Co= initial investment;; r = discount rate;; and N = number of time periods. 9 Modified Accelerated Cost Recovery System MACRS. The new accelerated cost recovery system, created after the release of the Tax Reform Act of 1986, which allows for greater accelerated depreciation than straight line depreciation. 14

15 book taxes and the taxes actually paid based on the five-year MACRS schedule. This difference is recognized as a reduction to the rate base. This reduction in rate base flows through to the ratepayer at the company s weighted average cost of capital. However, a third-party financed project flows through the five-year MACRS directly as a non-cash expense that reduces taxes. Q. Please describe the specific economic impact. A. Using the following example, I calculated the NPV of the ratepayer costs at the utility s Weighted Average Cost of Capital 10 (WACC). I evaluated the ratepayer costs and NPV under a rate-based asset using Normalization rules and third-party financed projects selling power through a PPA. I used the following assumptions: a) $1,000 asset placed in service;; b) ten year project life;; c) 30% ITC;; d) Five-year MACRS after CAPEX basis adjusted to 85% for ITC;; e) ten-year rate base depreciation;; and f) utility leverage of 50% debt. I compared the annual costs to ratepayer and the NPV under three scenarios: 1) utility rate base with ITC normalized, straight line ten year depreciation with an accumulated deferred income tax based on five-year MACRS at a 10% allowed return on rate base;; 2) third party financed passing through to the ratepayer the benefits of the ITC, five-year MACRS and the same debt structure with a 10% IRR on the equity cash flows;; and 3) third party financed utilizing 10 The WACC provides a firm s cost of capital in which each category of capital is proportionately weighted. The WACC equation is the cost of each capital component multiplied by its proportional weight and then summing: WACC= EV*Re+DV*Rd*(1- Tc) Where: Re = cost of equity;; Rd = cost of debt;; E = market value of the firm's equity;; D = market value of the firm's debt;; V = E + DE/V = percentage of financing that is equity;; D/V = percentage of financing that is debt;; Tc = corporate tax rate. 15

16 all the same assumptions except assuming a lower return of 9% IRR on the equity cash flows. We also assumed a typical 2.5% escalator in the third-party power price. The results can be found in Figure 2. Figure 2 As the Figure 2 demonstrates, the ratepayer both pays much higher costs in the initial term of the project and a higher total NPV of costs. The ratepayer pays on an NPV basis 5% more under a rate based scenario with normalization. The first-year cost to the 16

17 ratepayer would be 67% greater under the rate-base normalized scenario and over the first five years the average cost would be 30% higher. When evaluating the impact of a lower required return the equity cash flows, the ratepayer pays 8% more than if the project had been third-party financed utilizing 9% IRR on the equity cash flows. Utilizing this 9% IRR on equity cash flows, the undiscounted ratepayer impact is 74% greater in the first year;; and 34% greater in first five years. It should also be noted that the real economic impact on ratepayers is based on their marginal cost of capital and not the utility s WACC. (Utility WACC is used to calculate the NPV in order to have an objective standard.) In general, individuals and many corporations have a marginal cost of capital the value of their next investment that would be significantly greater than 7.3%. Discounting these ratepayer impacts at greater IRRs would further increase the discrepancy between the rate-based asset with normalization and the third party PPA. My Exhibit No. 1 provides additional support for this analysis. Finally, we created a simplified ten year example in order to facilitate the understanding of the financial impacts. These projects will be rate based over twenty or more years. We compared our results to a twenty year life. Assuming a twenty year life, utilizing assumptions that created equivalency in financial structure between the rate based and third party models (30% ITC, five year MACRS, 50% debt to asset value for both the rate-based asset and the third party, 7% interest expense on debt, 17

18 and 10% return for equity), the rate based asset resulted in a 21% greater NPV cost to the ratepayer than a third party financed project. Hence, extending the term from ten to twenty years results in an increase of over 330% in additional NPV of the costs. This result highlights the impact to the ratepayer in losing the time value of the tax benefits. The longer the life of the project under the rate based method, the greater the harm to the ratepayer from normalization. Q. Given this, has the Company adequately assessed third-party options? A. It is my opinion that the Company has failed to adequately assess third-party options in that the Commission's final order in the Brunswick CPCN case (Case No. PUE ) indicates that utilities must now provide "evidence of consideration of 11 actual third-party alternatives" as a prerequisite to receiving a CPCN. The Commission specifically referenced 2013 amendments to (A)(6), which now require that "a utility seeking approval to construct a generating facility shall demonstrate that it has considered and weighed alternative options, including third-party market alternatives, in its selection process." 11 Page 17 18

19 In the Commission s final order in the Company s 2014 IRP (Case No. PUE ), the Commission directed the Company to evaluate third party purchases including prices available through long-term purchase power agreements Accordingly, Dominion Virginia Power's future IRP filings shall include a more detailed analysis of market alternatives, especially third-party purchases that may provide long-term price stability. The Company's analysis of market alternatives shall also include, but not be limited to, wind and solar resources, and this analysis should examine wind and solar purchases at prices (including prices available through long-term purchase power agreements). Q. What is your recommendation to best assess third-party options? A. It is my recommendation that the Company and the Commission develop an aggregated RFP model similar to those used by the federal REAP Program, Georgia, Arizona or California, otherwise Virginia risks not fully utilizing the ITC. The Company can issue an RFP for up to a pre-defined total capacity of solar certain criteria. Once the Company selects the projects, the Commission would have the right to review all the projects and approve the group of projects, reject the group, or approve a subset. 19

20 Our financial modeling demonstrates that the ratepayer would benefit from expanding the target size for projects to include large scale commercial. The ratepayer benefits by capturing the 30% ITC even if the capital costs increase to account for the relative higher costs for large commercial scale relative to utility scale. The legislature determined that 500 MWs is in the public interest. Clearly Virginia does not have more than a few utility scale projects in pipeline that could be developed, financed, designed, constructed and brought on line commercially by December 31, The Commission should institute an RFP for an aggregated amount of MWs to include projects greater than one MW. In addition, the Commission should allow for projects greater than one (1) MW that incorporate multiple meters/sites. Examples of these types of projects would include county school systems, universities and colleges, public services facilities such as hospitals, local and state governments and organizations that own/control multiple buildings. The timeline for development through commercial on-line for these smaller scale projects allows these projects to have a much higher likelihood that they would be commercially on-line in time to qualify for the 30% ITC. Q. Would Virginia be starting from scratch in designing this RFP process? 20

21 A. No. Virginia is able to adopt the RFP process and structures that already have been developed. The existing procurement processes, together with any modifications needed in the Virginia context, would benefit the ratepayer by maximizing the amount of solar capacity able to be deployed before December 31, These processes essentially address the following: Project characteristics required e.g. location, size, technology/materials interconnection to the grid, documentation of right to develop project such as an option to lease agreement;; Information on the project developer;; Information regarding the financing;; and Information on the permitting of the project including environmental attributes. My Exhibit No. 2 provides an outline of the various RFP processes as compared to the Company s most recent Brunswick natural gas CCGT RFP. Q. You mentioned the REAP Program, what is that? 21

22 12 A. The REAP program is an aggregated solar procurement program that leverages collective purchasing power to secure the best available solar project pricing and terms. REAP Program pricing and terms can be used by participants to meet their individual and unique solar project needs. Five (5) key elements of REAP are (1) access to competitive pricing, (2) a predesigned, streamlined solar competitive bidding process, (3) minimized administrative strain, (4) competitively procured project costs, as well as (5) standardized terms and conditions of service [andirm] pricing for solar installations so that projected returns on investment can be more accurately computed. While REAP is currently limited to public education entities, it is important to note that REAP can serve as a resource in developing a competitive bidding process specifically for solar - which is far less complicated that the process for say, an electrical generator powered by gas. Q. Do you have any concluding thoughts you would like to share?

23 A. MDVSEIA supports utility scale solar development for Virginia. However, the following facts demonstrate that Virginia needs a new process for selecting projects: (1) the General Assembly determination that up to 500 MWs of solar is in the public interest;; 2) the inability for the utility to fully pass along the tax benefits to the ratepayer because of normalization;; 3) the expiration of the 30% ITC on December 31, 2016;; and (4) the lack of a sufficient existing pipeline to maximize the federal ITC. Multiple states have demonstrated that an RFP that selects multiple projects up to a pre-determined capacity provides an efficient process for evaluating against pre-determined criteria and selecting projects. Q. Does this conclude your direct testimony? A. Yes. Thank you. 23

24 APPENDIX A BACKGROUND AND QUALIFICATIONS OF FRANCIS HODSOLL 1261 Wild Hawthorn Way Reston, VA Francis@eefrontiers.com (703) Dynamic, analytical and networked energy executive providing strategy, project development, business development, policy advocacy, performance management, and general management. Highly networked in both the private and public private energy sectors. Leadership in strategic planning, new business opportunities, building ventures, and performance improvement. Deep expertise in energy markets, technologies, legislation, and regulations. Successful track record at structuring, negotiating and closing transactions. Strong capabilities in project finance and general finance including project structuring, debt and equity financing, and risk management. Dedicated to values based leadership, coaching, empowering subordinates and developing high performing teams. FOUNDER AND PRESIDENT PROFESSIONAL EXPERIENCE 2011-Present E&E FRONTIERS Fairfax, VA Energy management consulting firm advising leaders in emerging and traditional energy frontiers, providing strategy, finance, business development, project development, performance management and policy advocacy. Trained senior Afghanistan government officials in energy economics, finance and negotiations. The trainings focused on the development of their natural gas resources and natural gas powered electricity generation. As temporary COO, developed strategic recommendations and analytical tools for energy retail arm of Nextera Energy. Analytical tools are providing leadership real-time sales KPIs by utility markets and market segments. Based on my 24

25 recommendations, leadership advanced recommendations to focus resources on top performing markets, to create differentiated service models, and to redeploy freed-up resources on increasing operational performance. Recommendations are expected to increase margins 3-4X. Founded Virginia Advanced Energy Industries Coalition (VAEIC). VAEIC is a business advocacy group that promotes open markets for clean and secure advanced energy technologies in order to create jobs and position Virginia as a magnet for talent and innovation in the advanced energy sector. Raised startup funding from NextGen Climate (Tom Steyer), Advanced Energy Economy, the Energy Foundation and numerous advanced energy businesses. The coalition includes OPower, Washington Gas, SolarCity, Standard Solar, Skyline Innovations, Ameresco, Trane, Enernoc, Covanta, HelioSage, APEX, Antares SEIA, AWEA, VA Energy Efficiency Council, VA Center for Natural Resources, the Electric Vehicle Association. Launched Electricity Development Partner (EDP), an international electric utility company for distributed generation / micro-grid operations in Afghanistan: conceived concept, created plan, developing partnerships and led implementation. $200 million initial market (25%+ unlevered ten year IRR) with $13 billion global market. Led a U.S. military team (Taskforce for Business and Stability Operations) for the development of Afghan electricity capacity and a private sector (Independent Power Producers) industry. The team defined and modeled financial structures, conducted market and economic research;; evaluated investors and owner/operators;; developed partnerships with key stakeholders (Ministry for Energy and Water, Da Afghanistan Breshna Sherkat, Ministry of Rural Rehabilitation and Development, and local and regional Shuras);; and negotiated with the Afghan government. Led economic analysis for South Korean coal and natural gas demand, supply, and price forecasts to 2030 including assessing the impact of a nuclear power moratorium in East Asia. Developed forecasts for U.S., China, Japan, Germany, France, and the United Kingdom. Study performed for Korea Energy Economics Institute through the University of Delaware. Supported strategic planning and business development for LMI, a private, not-for-profit management consultancy to expand its energy practice. Projects included expanding its asset management software and services into the electric utility space and expanding its energy efficiency services. Supported the launch of a new renewable energy retail company ($200 million revenue opportunity): provided my client strategy, utility negotiations, partnership development, legislative advocacy, and strategic communications services. Developed strategy for monetizing Renewable Energy Credits through local utilities. Represented two clients in the development of the State of Delaware Pilot Program for the Procurement of Renewable Energy Credits. Provided advice on market dynamics, financing models, and procurement approaches. Secured $3 million in contracted revenue for the projects. 25

26 Negotiated a solar lease on behalf of a host for a 7 megawatt photovoltaic project. Secured $2 million in contracted revenue. Led MD-DC-VA Solar Energy Industries Association. Transformed a thirty year old association with new staff, new systems, a 300% increase in revenue and strengthened partnerships. Developed partnership with the national Solar Energy Industries Association to govern joint advocacy. Led solar industry efforts and testified before the VA State Corporation Commission (SCC) in order to reverse punitive rate structure on solar systems. VICE PRESIDENT PACE GLOBAL ENERGY SERVICES Fairfax, VA Company that provides strategic advisory, commercial management and transactional services in all types of energy including fossil fuels, fossil fired electric generation, solar, wind, biomass and other renewable energy. Led a team and negotiations for 10MW solar photovoltaic power plant for electric utility hosting the project. We structured and successfully negotiated complex five party transaction including valuing long term (25 year) energy, capacity, ancillary services, and tradable Renewable Energy Credits. Led state and local negotiations and led public relations efforts. Conceived, developed and managed group to develop distributed renewable projects including wind, solar, waste to energy, and biomass. Within 18, months, Pace developed 15 mws of distributed projects and built a 35 MW project pipeline. Built an asset management service targeting medium sized public power entities and providing energy management, risk management, asset management and strategic advisory services. Pace Global generated over $30 million in revenues. Led the team that successfully negotiated a 300 mw natural gas powered combined cycle power plant for the public power host. Led market and regulatory assessments;; pro forma analyses;; presentations to City Council and press. Negotiations resulted in an option to lease, and an option on a Power Purchase Agreement including all commercial terms and performance requirements. Project was sold to Calpine. Led a team that developed strategies for commercial management of the environmental compliance markets: the Regional Greenhouse Gas Initiative (RGGI), the first US market-based cap and trade carbon market;; and the SO2 and NOx allowance markets. CFO

27 INDUSTRIAL POWER GENERATING COMPANY, LLC Richmond, VA Company designs, develops and operates distributed and renewable energy power plants. Ingenco employees 130+ staff and, at that time had $20M+ in annual revenue with a projected $175M+ in revenue over the next 3 years. Recruited to improve financial management by majority owner, First Reserve, a private equity firm focusing exclusively on the energy industry with over $12.5 billion under management. Led debt financing for INGENCO to fund future $40M + construction project this included developing company memorandum and projections and leading multi-party discussion on terms. Managed the Treasury, Controller and Human Resources functions including cash, risk management, banking relationship. DEPUTY DIRECTOR & CFO U.S. DEPT OF INTERIOR, MINERALS MANAGEMENT SERVICE Washington, DC Federal agency with a $300M operating budget and 1,700 employees. MMS manages the nation s natural gas, oil and other mineral sources on the outer continental shelf;; also collects, accounts for and disburses $8B+ in leasing revenues. Recruited by the White House to support the Director in policy formulation and operations. Directed the development of the offshore alternative energy program mandated by the Energy Policy Act of Developed policy objectives, market and economic analyses, regulations, strategic communications, and public outreach. Oversaw the $3B oil and natural gas Royalty In-Kind marketing operation;; developed risk management policies and market risk metrics for the operations. Risk policies were approved by the Cabinet Secretary. Senior executive with authority to sign off on regulations;; provided executive oversight for the development of numerous regulations impacting federal revenues, leasing rights, and safety. SENIOR POLICY ADVISOR U.S. DEPT OF ENERGY Washington, DC Federal agency that oversees and manages America s energy and nuclear security, scientific discovery and innovation, and environmental responsibility. 27

28 Developed analytical techniques and tools for assessing federal policy options in support of nuclear energy;; Congress enacted the recommended policy options in The Energy Policy Act of Acted as a liaison between program management for a 5,000 per month medical claims operation and senior Department of Energy officials. Program management philosophy was fundamentally changed, operations were restructured and the program achieved sustained month-on-month double digit efficiency increases. CFO / Business Development A.I. Solutions, Inc. Lanham, MD Company provides aerospace engineering services, mission-critical IT services and commercial-off-the shelf (COTS) analysis software for satellite missions. Oversaw accounting, billing, budgeting, contracting, and business development. Restructured the company s credit facilities resulting in improved credit terms and an expansion of the working capital revolver. Led the creation of business development strategies resulting in expanded service offering and expanded customer base to the aerospace industry. Company has achieved 30% annual revenue growth. Engagement Manager, Strategy Consultant McKinsey & Company, Inc. Houston, TX and Charlotte, NC Clients included integrated electric utilities, energy trading and marketing entities, major oil companies, and chemical companies. Assessed competitive positioning for the non-regulated electricity and natural gas subsidiary of a foreign Global 1000 energy company including service offerings, capabilities, market perceptions, and corporate commitment resulting in recommendation and The Board s approval for divestiture. Performed valuations of differing portfolios of electricity generation plants based on multiple deregulation scenarios and assisted in the electricity deregulation negotiation strategy for the client s Public Utility Commission hearings resulting in over $100 million in value creation. Developed risk management strategies and processes including IT architecture for electricity and natural gas trading and marketing company eliminating multi-year multimillion dollar losses. 28

29 Electricity Trader and Natural Gas Analyst Tenneco Energy Diversified energy company. Bought in 1996 by El Paso Energy. Houston, TX Power trader: Assisted in creating an electricity trading desk, traded electricity options, and developed option pricing and trading tools. Natural gas analyst: supported the structured trading desk providing market analysis and financial modeling for long-term structured gas contracts including LCD pre-pay transactions and transactions with embedded options. Developed trading and pricing tools for path contingent options. MASTERS IN SCIENCE IN BUSINESS ADMINISTRATION MIT SLOAN SCHOOL OF MANAGEMENT BACHELOR OF ARTS IN ECONOMICS COLBY COLLEGE EDUCATION AND TRAINING Cambridge, MA Waterville, ME SPECIALIZED TRAINING Leadership, Project Management, Financial Analysis, Strategy COMMUNITY / VOLUNTEER WORK Board Director and Treasurer, MD-DC-VA Solar Energy Industry Association regional solar association State representative to the national Solar Energy Industries Association Founder, (SSHARE) Volunteer Group For DC primary education. Former Treasurer, NSOvation Council the young benefactors of the National Symphony. Consultant (Gratis), DC Children s Hospital camp for disabled children, Local arts council and repertory theater. 29

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32 32 MDV-SEIA Exhibit No. 1 Witness: FH Schedule 1 Page 1 of 1

33 Project Brunswick Project Information Required (2014 RFP Instructions, Page 15) -Location: facilities interconnection to the Dominion Zone, BGE, PEPCO, or Eastern portion of Allegheny Power Systems Zone (2014 RFP Instructions, Page 3) -Size: up to approximately 1,600 MW (2014 RFP Instructions, Page 7) -Technology: must utilize existing, proven technology with demonstrated reliable generation performance (2014 RFP Instructions, Page 7) -Materials: facility has the agreements, assets, or other arrangements necessary to support the fuel strategy -Documentation of right to develop Developer Information Required (2014 RFP Information Form, Financial Information sheet) -PPA Counterparty and Guarantor entity -Guarantor s relationship to PPA Counterparty -Letter of Credit Provider -Estimated cost to develop & construct -Equity interests of PPA Counterparty (audited), 2013 (audited), and 2014 year-to-date financial information including a Balance Sheet, Statements of Income, Statements of Cash Flows with footnotes Financing Information Required (2014 RFP Instructions, Page 8) -Proposal must be accompanied by either affirmative state that Bidder takes no exception to form of PPA or a fully marked-up PPA reflective of its bid (2014 RFP Information Form, PPA Price & Terms Summary) -Capacity pricing ($/MW-Day for first contract year) - Capacity Annual Escalation Factor/Index -Portion of Capacity Price representing O&M, tax and insurance costs -Non-Fuel Variable Annual O&M Escalation Factor/Index plus Description of components -Start Price ($/Start for first contract year) plus Start price Annual Escalation MDV-SEIA Exhibit No. 2 Witness: FH Page 1 of 3 Permitting Information Required (2014 RFP Instructions, Pages 25-26) -Permitting activities for each major permit -Certificate of Public Convenience and Necessity -PJM Queue process -Local approvals, such as conditional use permit 33

34 Georgia Power Location: Georgia, separately metered, connected directly to a distribution circuit of the Georgia Power distribution system (Page 17) Size: Georgia power has proposed this project to construct a total of 100 MW. They broke up the MW into groups based on differences on how they are purchased. (Page 5) -Group A (50 MW) is for a competitive RFP for DG solar photovoltaic generating facilities in Georgia. It will be broken down further into a 40 MW group (for facilities from 1-3 MW of Alternating Current) and a 10 MW group (for facilities from 500 KW-1 MW of AC). (Page 5) Company provides a meter, distribution transformer and up to 500 ft. (Pages 27-28): Acknowledgement from bidder that proposal meets requirements, and that bidder agrees to all of Georgia Power s terms General information on bidder s company Financial and credit information Detailed description of security/credit instruments proposed Any limitation on use or availability of Solar Output Pricing proposals Term of proposal Facility information Performance data Interconnection data Requested date Factor/Index -Fuel Cost Index Formula for First and Second Fuel Sources (Page 17): Provide pricing proposals, either fixed over entire term or escalate year to year (no annual price shall be lower than the previous year) Price for solar output shall not exceed listed prices (Listed prices are provided on page 17 of RFP) Renewable energy credits and environmental attributes must be bundled in price of solar output (Page 12, Section F) Commercial Operation Authorization (Page 18) 34

35 of interconnecting line. Additional interconnecting resources are the responsibility of bidder. (Page 18) Southern California Edison Location: Required to be in Rancho Cucamonga (Page 8, section 2.04) Size: Minimum contract capacity as 1.9 MW. ( Page 8, section 2.04) Date: gives latest date which if the DG is not installed by, the contract is terminated (Page 8, section 2.04) Detailed Automated Load Reduction Scheme (ALRS) required. An ALRS is designed to automatically disconnect the Designated Load from the SCE s distributed system to effectuate the Physical Load Reduction Assurance required under the DGS Agreement. (Page 7, section 2.02, e) Any changes to desired cost listed in RFP for the ALRS must be (Pages 10-12, section 3.06): 1. DG needs to complete and sign a template proposal structure letter 2. Submit project proposal template 3. Provide Distributed Generation Facility Description and one-line diagram 4. Provide designated load description 5. State any proposed changes DG made to Pro Forma DGS Agreement (Attached to RFP) 6. Site description: Legal description of site and DG s legal control of site. Also, a site map. 7. Must sign and provide Distributed Generator Acknowledgements and Designated Load Latter. Exhibits for these included -DGs must submit proposals based on assumption that DG s will post SCE s pro Collateral Amount, which is $20 for each kilowatt of the Contracted Capacity of the Distributed Generating Facility (Page 15, section 5.02) -Collateral Amount accepted in form of cash deposit or Letter of Credit (Page 15, section 5.02) (Page 7, section 2.03): -DG must disclose whether or not it is an SCE affiliate -DG must obtain a letter of agreement from each Designated Load Customer in order to provide evidence of load reduction capability. 35

36 explained. (Page 30) in RFP. 36