PowerGenz and the Meltemi Wind Energy Development Company

IntroductionAt the end of October 2009, the clock was ticking for Juan Ricardo. Ricardo, the Director of Development at PowerGenz Energy knew there were only 35 days remaining before the 60-day exclusivity period on their term sheet agreement with Meltemi Energy expired on December 1. Ricardo needed to make a recommendation to PowerGenz’s board, but right now he still had a long list of unanswered questions. PowerGenz, an electricity wholesaler, or in industry jargon, an independent power producer (IPP), was evaluating a portfolio of wind projects being sold by Meltemi, a developer of large-scale wind projects. Acquiring such projects was critical to PowerGenz’s future growth strategy, but a poor investment decision would be a serious setback for the company, and a potential disaster for Ricardo’s career aspirations. With this in mind, Ricardo pored over the engineering reports, environmental studies, and other documents that Meltemi had provided. Ricardo knew there was never enough information to insure success; he needed to make a sound recommendation based on the information that was available.

The Electric Power IndustryThe U.S. electric power industry produces and delivers electricity to approximately 118 million households and 20 million businesses. The first commercial generation of electricity in the U.S. was the coal-fired Pearl Street Power Station in lower Manhattan built by Thomas Edison in 1882.1 Today in the U.S. there are approximately 5,800 operating power plants of 1 megawatt or more.

The electric power industry performs four critical and separate functions:

1. Generation2. Transmission3. Distribution4. Supplying to Customer / Retailing

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This case was written by John Chaimanis M’07 Graduate of the Olin School of Business at Babson College with assistance from Professors Richard Bliss and Michael Harrity. This case should be read in conjunction with Utility Scale Wind Project Development: 101, Bayside Energy Advisors, John Chaimanis, May 7, 2012.

© 2013 by John Chaimanis. No part of this publication may be reproduced, stored in a retrieval system, used in a spreadsheet, or transmitted in any form or by any means – electronic, mechanical, photocopying, recording, or otherwise – without the permission of copyright holders.

1 For an accessible history of the electric industry and deregulation, see the following from the Smithsonian Institution’s website: http://americanhistory.si.edu/powering/ NO

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Exhibit 1 shows these functions and describes the critical success factors for each. For most of its first 100 years, companies in the electric power industry took two forms: municipal ownership or state-regulated monopolies. This was the result of the desire to balance the benefits of a natural monopoly with concerns of pricing abuse for a necessary commodity, and the structure worked well for decades. However the energy of the 1970s, which increased electricity prices by 500% and a national trend towards industry deregulation (e.g., airlines, transportation, telecommunications, and financial services) changed everything.

Deregulation of the electric power industry began with the Public Utility Regulatory Policies Act (PURPA) in 1978, continued with the Energy Policy Act of 1992, and culminated with rules issued by the Federal Energy Regulatory Commission (FERC) in 1996. The most important aspect of deregulation was decoupling the ownership of generators, who produce the electricity, from the distribution companies, who sell the electricity to the end users. The deregulation created independent power producers (IPPs who own the power generation facilities) and the load serving entities (LSEs who own and manage the transmission and distribution – T & D – network). The FERC rules promoted competition in the markets for wholesale power, and mandated that utilities allow IPPs access to their transmission lines for a fee. Prior to deregulation, utility companies generally owned the entire generation-transmission-distribution infrastructure and managed the retail part of the business (metering, billing, collections, etc.).

One of the arguments in favor of deregulation was that breaking up the utility company monopolies would encourage more efficient investment, generation, and distribution of power leading to lower costs driven by market forces. Prior to deregulation, there was not an incentive to build new or more effective generation projects which could produce power at a lower cost (e.g., gas turbines or nuclear reactors), because the utility had no cost pressure from competition. In addition, regulation guaranteed the utilities a fixed profit margin on top of their costs, so higher costs actually made the utility more money.

IPPs make their money by selling electricity, measured in megawatt hours (MWh – a measure of electrical power over time) into the wholesale power markets and are paid in dollars - $/MWh. The vast majority of buyers in the wholesale power markets are LSEs that have to buy the power to service their customers. The total demand from the customers of an LSE at any moment is called the load. Other participants in the wholesale power markets include banks and traders who are looking to hedge or profit from movements in the price of power and the demand of the load. IPPs profit is based on the difference between the price they receive from LSEs for the MWh they generate and the fixed and variable generation costs they incur including debt service, maintenance and operating costs, and fuel. LSEs earn a return for the management and maintenance of the transmission and distribution network that they own and the rate of return LSEs receive is regulated by state utility commissions. Exhibit 2 outlines the relationship between project developers, IPPS and LSEs.

Deregulation has occurred at different rates across the county and with varying levels of government participation. In some deregulated markets, LSEs own the distribution system and have a monopoly on selling the power to the end users. However, in other markets, there is full competition amongst LSEs to sell power to end users, and the end user is able to choose amongst

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numerous suppliers. These markets are called retail choice markets, and represent the most unregulated power markets from generation to end use.

Deregulation has its drawbacks, and some jurisdictions have essentially failed to adopt any real measures to create a market-driven electricity industry. One of the challenges in a deregulated market is financing the massive upfront investment required to build a new power plant given the uncertainty of future power prices in the wholesale market. A common approach to deal with this disconnect is for the IPP to enter into a long term power purchase agreement PPA with a credit-worthy LSE for the majority or all of the power for a term up to 25 years. This gives investors in the power plant a level of confidence that if the plant operates as expected over the term, the revenues generated by the facility will provide an appropriate rate of return. This is a risk averse approach which effectively limits the upside potential, in exchange for a fairly certain future revenue stream.

The alternative to a PPA is to sell the power into the wholesale power markets on a “merchant” or un-contracted basis. A merchant generator takes on substantial risk that the wholesale power prices drop or remain low, however, they can also make significantly higher returns for the investor if volatility or the price of power increases over time. See Exhibit 3 for historical wholesale prices of electricity in ERCOT, an organized electricity market largely located in Texas.

Generation: From Renewables to Fossil Fuels and BackSome of the earliest utility-scale generating stations in the US were hydroelectric. One of the largest of its time was the 75 megawatt (MW) 2 Niagara Falls Power Company Powerhouse #1 which was developed by George Westinghouse and financed by JP Morgan, and went into operation in 1895.3 Throughout the 20th century, hydropower has remained a source of electrical generation in the US; however burning wood and ultimately fossil fuels became the dominant method of generating electricity. World War II changed the landscape of the world in many ways – most important to the power generating industry was the advent of harnessing nuclear power. As of 2011, nearly 20% of the power in the US was generated by nuclear generating stations, nearly all of which were commissioned between 1958 and 1974. Nuclear was seen as a safe, “unlimited” source, of low emission power that provided freedom from overseas fuels, and a long term fixed cost. On March 29th, 1979 the Three Mile Island power plant in Pennsylvania experienced a partial core meltdown. Although there were no deaths or serious injuries to workers or nearby residents, the accidents, considered to be the worst ever among commercial reactors in the U.S., changed the public’s perception of nuclear energy as both clean and safe.

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2 For reference, “…conventional generators, such as a coal plant, a megawatt of capacity will produce electricity that equates to about the same amount of electricity consumed by 400 to 900 homes in a year. For renewable energy such as wind or solar, the equivalent is even less because they typically produce less energy than conventional generators since their fuel source is intermittent.” http://www.utilipoint.com/2003/06/what-is-a-megawatt/

3 http://www.niagarafrontier.com/power.html (accessed on 1/23/13)

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Since the advent of the first generating station, individuals, companies, and countries have searched for alternate forms of cheaper, more reliable energy production. In almost all markets, coal, natural gas and legacy nuclear facilities continue to be the lowest cost alternative. Non-hydro renewable energy, including electricity generated from wind, solar, biomass and bio gas, is getting cheaper due to technological advances and manufacturing economies of scale. However, on a strict dollar per kilowatt hour basis electricity from renewables generally cost more, and in some cases significantly more, than fossil fuel based sources.4

Where market mechanisms have failed to increase the share of electricity produced from renewables, legislative process has succeeded. In 1983, Iowa passed legislation establishing a renewable portfolio standard (RPS).5 A state RPS establishes a requirement for a regulated load serving entity (LSE) to purchase a certain amount (or percentage) of renewable energy, and these amounts generally increase over time. These policies are legislatively driven, and can favor one technology over another. As shown in Exhibit 4, today 29 states, the District of Colombia, and Puerto Rico have explicit RPS and 8 states have renewable goals.6 Each state has slightly different legislation and consequences for non-compliance; however, all states with RPS create demand from LSEs for renewable power that might not otherwise exist. As is typical in any commodity market, low cost remains king, and LSEs typically purchase electricity from renewable sources only up to the point where they have met their RPS obligation.

Utility-Scale Wind Generation in the US“From 1974 through the mid-1980s the United States government worked with industry to advance [wind] technology and enable large commercial wind turbines. The NASA wind turbines were developed under a program to create a utility-scale wind turbine industry in the U.S. With funding from the National Science Foundation and later the United States Department of Energy (DOE), a total of 13 experimental wind turbines were put into operation, in four major wind turbine designs. This research and development program pioneered many of the multi-megawatt turbine technologies in use today, including: steel tube towers, variable-speed generators, composite blade materials, partial-span pitch control, as well as aerodynamic, structural, and acoustic engineering design capabilities. When oil prices declined by a factor of three from 1980 through the early 1990s,[24] many turbine manufacturers, both large and small, left the business. The commercial sales of the NASA/Boeing Mod-5B, for example, came to an end in 1987 when Boeing Engineering and Construction announced they were "planning to leave the

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4 Note: This assertion is the subject of much debate, as the true cost of fossil fuels is distorted by direct and indirect subsidies and the exclusion of the cost of negative externalities like acid rain, air pollution and CO²’s contribution to climate change. That said, the authors have chosen to use the commonly perceived notion of the times in the absence of concrete information to the contrary.

5 http://www.c2es.org/us-states-regions/news/2009/iowa-rps (accessed 1/23/13)

6 http://www.dsireusa.org/ accessed May 24, 2012

market because low oil prices are keeping windmills for electricity generation uneconomical."[25]

Later, in the 1980s, California provided tax rebates for wind power. These funded the first major use of wind power for utility electricity. These machines, gathered in large wind parks such as at Altamont Pass would be considered small and un-economic by modern wind power development standards.”7

The wind industry in the United States is quite robust and predicted to grow.

“The U.S. wind industry now totals 48,611 MW of cumulative wind capacity through the end of the first quarter of 2012. There are over 8,900 MW currently under construction involving nearly 100 separate projects spanning 31 states plus Puerto Rico. The U.S. wind industry has added over 35% of all new generating capacity over the past 5 years, second only to natural gas, and more than nuclear and coal combined. Today, U.S. wind power capacity represents more than 20% of the world's installed wind power.

Today, the U.S. wind industry represents not only a large market for wind power capacity installations, but also a growing market for American manufacturing. Over 470 manufacturing facilities across the U.S. make components for wind turbines, and dedicated wind facilities that manufacture major components such as towers, blades and assembled nacelles can be found in every region.”8

Three key Federal tax-driven incentives level the playing field for wind projects as they compete against other large infrastructure projects for capital. As an investment, wind projects benefit from accelerated depreciation (modified accelerated cost recovery system, or “MACRS”) calculated over an allowably short 5-year life for depreciation purposes, a federal production tax credit (PTC) available during the first ten years of operation, and as an alternate to the PTC, they qualify for an investment tax credit (ITC). Additionally, there may be certain incentives available on a state by state basis and local level including state RECs, and payments in lieu of taxes (PILOT) agreements.

Another market mechanism which has evolved is the Renewable Energy Credit (REC) market. RECs are intangible commodities created via state government incentives every time a MW of renewable electricity is generated. RECs assign the buyer with credit for the renewable electrical energy produced and are acquired by LSEs to confirm their compliance with state RPS requirements. RECs can be sold as a “bundled product” along with the electricity itself or RECs can be “decoupled” and sold independent from the energy. The REC market is quite fragmented and valued according to the state that they are generated within and at times according to the technology that created them. For example a solar REC (SREC) from the state of Massachusetts trades separately and has a different value from a wind REC from Texas. Factors which impact

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7 http://en.wikipedia.org/wiki/History_of_wind_power accessed May 24, 2012

8 http://www.awea.org/learnabout/industry_stats/index.cfm accessed May 24, 2012

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the value include the state by state RPS obligations, supply and demand, and the various state by state alternative compliance payments.

Monetizing Electricity Produced by the WindThe business of selling electricity generated from wind is grounded in the same premise as selling power from plants burning fossil fuels: produce at a low cost MWh of energy when LSEs need the power to satisfy their customers’ demand. A traditional fossil fuel burning plant has an upfront cost to build, annual operating costs, and the cost of the fuel they burn. A wind facility has a large upfront cost and annual operating costs, but no ongoing fuel cost. A wind facility also has an advantage over other generating plants in states where there is a mandated RPS. As a result of these RPS requirements, LSEs generally contract to buy all of the energy the wind turbine can produce whenever it is produced.

All generators have a Nameplate Capacity Rating in megawatts (MW), which represents the maximum amount of power that can be generated at a single point in time. MW is a static measure of power, equal to 1,000 kilowatts (KW). MW is the standard used for capacity ratings for utility scale generation plants, while KW is used for small scale generators. Electrical energy is measured in a quantity of power over time. A megawatt hour (MWh) is a quantity of electricity produced over one hour. Since there are 8,760 hours in a year, in theory a 1 MW generating plant operating at 100% capacity over a full year would produce 8,760 MWh. A Capacity Factor (CF) is a percentage representing the actual energy the specific power generating unit is expected to produce over a year relative to its rated capacity at 100% operating efficiency. Because all types of power generators require maintenance and downtime, no plant operates at a capacity factor of 100%. For a wind turbine the calculation of the capacity factor must include an estimate of the wind resource itself, and this estimate is most accurate when it is based on data collected from the specific site and elevation of the turbine over a period of at least a year.

For example, the theoretical maximum a 50MW wind facility is capable of producing is 8,760 hrs. X 50 MW = 438,000 MWh. However after accounting for various loss factors and the annual expected wind profile, the facility may be projected to produce 197,500 MWh, which equates to a 45% capacity factor (197,500 / 438,000 = 45%). Engineering firms which specialize in power generation technologies and meteorology provide critical input to IPPs considering acquiring a wind facility by estimating the capacity factor for specific sites and the wind turbines to be sited there.

PowerGenzPowerGenz is privately-owned and was founded in 1997 as response to the opportunity created through the power industry’s deregulation. The company generates the majority of their revenue through the ownership and operation of utility-scale electric generation projects in the United States. PowerGenz is an IPP that currently owns approximately 5,500 MW of generating capacity consisting of coal, natural gas, and wind power.

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PowerGenz’s assets are quite profitable, which also means that the company has a large tax liability at the end of the year. The majority of PowerGenz’s plants sell their output under long-term fixed price PPAs with LSEs. These long term PPA contracts are ideal for securing project debt but profit growth is generally limited because improved margins are limited to operational and technological improvements. A few of PowerGenz projects have no long term contracts, and instead sell into the wholesale power markets on a merchant basis. This capacity affords PowerGenz an opportunity to increase profits if wholesale electricity prices rise, but it also adds to the volatility of PowerGenz’s revenue and net income.

For PowerGenz, meaningful growth in profits requires an increase in the company’s generating capacity. Like many investors in utility companies, PowerGenz’ owners are relatively risk averse. The company’s strategy for growth was through acquisition, either of operating facilities or of facilities where the early-stage risks of land acquisition and regulatory approvals has been overcome. Anticipating a recovering national economy and increased demand for electricity, PowerGenz set a target of investing $500M in new generating capacity over the period of 2010 and 2011.

The strategy included targeting wind generation, since PowerGenz had developed the capability of managing the construction and operation of wind turbines and large scale wind farm. PowerGenz’s management team did not pursue high-risk/high-reward early-stage project development (aka “greenfield” development) of the wind farm sites themselves. Instead PowerGenz preferred to acquire construction-ready development projects from independent developers who received a premium for the risks they have overcome in securing approvals for wind farm sites.

Meltemi EnergyMeltemi Energy, (named after the strong Greek dry north winds prevalent in the summer in the Aegean Sea) is an independent developer of commercial-scale wind projects. The principals of Meltemi have no interest in owning or operating the projects that they develop. Their business model is to identify ideal locations to site projects and to accumulate all of the necessary permits and entitlements to create a construction-ready project. Meltemi then seeks a buyer for the asset before construction begins. Meltemi’s business is high risk and high reward: developing a single project can take up to five years and cost as much as $5,000,000.

Development costs can include consulting expenses for environmental and meteorological studies, permit filing fees, engineering feasibility costs, option and/or lease payments, interconnection study and filing fees, transmission study fees, legal fees, and design costs, to name a few. Hundreds of thousands of dollars can be invested in a proposed project that is later abandoned because of insurmountable obstacles. However, returns on a successful project could yield Meltemi as much as 10 times their investment. Sophisticated and successful developers like Meltemi typically have a portfolio of projects that they are developing simultaneously and they expect that the winners will more than compensate for the losers.

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Wind project development has many similarities to real estate development, and often wind project developers have had prior experience in real estate, oil and gas land acquisition, or telecom land development. There are five key components to developing a successful wind project:

1. meteorological analysis

2. land control

3. permitting & entitlement

4. interconnection & transmission

5. power sales

The fundamental drivers of value from a wind project are the interplay among the wind resource itself, the cost to construct the wind turbine and its interconnection to the power grid, and the price which can be obtained for the power output from the project.

Meltemi has successfully developed a number of utility-scale projects, some with turbines having a combined generating capacity of 200MW. Meltemi’s success can be attributed to their high-level local connections, aggressive negotiation style, and their proven ability to deliver on their commitments.

The TransactionIn May of 2009, PowerGenz and Meltemi were introduced at Windpower, the American Wind Energy Association’s annual conference in Chicago. Meltemi shared a portfolio of wind projects, which consisted of five projects in various stages of development, totaling 670MW. Exhibit 5 contains information on the five projects. The CEO of Meltemi, Brian Stonewall, claimed that two of the projects “would be construction-ready in two months, and one was ready to go today.” Mr. Stonewall wanted to sell the whole portfolio “as is” for $35,000/MW, or $23.5 million. Meltemi was also willing to sell only the “ready to go today” project, a 150 MW development named Cedar Crescent Mountain for $15 million, or $100,000/MW. Whether PowerGenz acquired the entire portfolio or just one project, they would pay Meltemi for the development rights, and then assume 1) the responsibility and cost of completing the permitting process and 2) pay the cost of constructing the wind turbines, accompanying infrastructure, and the power lines connecting the project to the grid.

On October 1, 2009, PowerGenz and Meltemi signed a letter of intent (LOI) which outlined the basic business terms of the proposed transaction including the option to purchase either the five-project portfolio for $23.5 million or just the Cedar Crescent Mountain project for $15.0 million. The LOI gave PowerGenz 60-days to complete their due diligence and negotiate the full and final terms of the purchase agreement. The transaction would then close no more than thirty days later.

PowerGenz put three of their in-house developers on the Meltemi due diligence team: Director of Development Juan Ricardo, and analysts Hector Woodford and Z. Plateado. The team sifted through 1,000s of pages of leases, interconnection studies, environmental reports, permit applications, and meteorological reports. Of the ‘development stage’ projects, two totaling 320

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MW – Sawtooth Butte and White Pines Bluff – were merely outlines on a map with partial site control consisting of a handful of leases, preliminary screening level wind analysis, and interconnection requests, but none of the expensive and timely interconnection studies. Two other projects totaling 200 MW – Jagged Peak and Blue Moon Valley – had more extensive meteorological data, 90% site control, some environmental studies completed. Meltemi had also secured signed interconnection agreements and had completed some of the crucial permitting milestones, but they had not contracted to sell the power from these two projects.

Cedar Crest MountainThe 150 MW Cedar Crescent Mountain development was definitely the most mature project in the portfolio and this is where the PowerGenz team focused their due diligence. The project was located on sprawling ranch land populated by mesquite brush and used as grazing land for Texas longhorn cattle, as well as hunting ground for deer, rabbits and quail. It was situated on top of a unique geological feature known as the Crescent Escarpment which rose over the plains below and created an enhanced wind regime relative to the surrounding region. The project was the only one in the portfolio with a signed Power Purchase Agreement PPA. The 20-year PPA contract carried a very attractive bundled price of $66/MWh9. However, the PPA also gave the purchaser of the power, Longhorn Electric Co., a termination right if the project was not fully constructed and generating power within four months of the required Commercial Operation Date (COD) of November 30, 2010.

The Cedar Crescent project had a signed interconnection agreement (IA) with South Texas Wires and Transmission Company, which prescribed for relatively minor infrastructure upgrades totaling approximately $4.95 million. Meltemi’s in-house engineers estimated it would take four months to complete the upgrades, but included language in the utility IA which gave the interconnection contractor up to 12 months to complete their work. The interconnection work could begin simultaneously with the start of the balance of plant (BOP) contract.

The entire project area was controlled, with 80% of the project owned by a single landowner and the remaining 20% owned by 15 others. The project required construction of a five-mile transmission line to connect to the existing substation which was the interconnection point specified in the IA. While the entire wind farm project area was already controlled under lease, there remained a 1/2 mile strip of land for the transmission right of way that still needed to be acquired (Exhibit 6).

The wind energy resource data for the Cedar Crescent site had been collected from a single meteorological tower over a three year period. It indicated excellent wind speeds and duration; however for a project this size – approximately 100 wind turbines covering about 20,000 acres of land – and with somewhat varied terrain, it was industry best practice to have onsite data collection from at least four towers, with at least one full year at each location. This somewhat limited data on the wind resource could not only affect the accuracy of the electricity output forecast, but it might also make the lenders more cautious. PowerGenz was typically able to

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9 Bundled in this case means that the electric buyer is buying both the RECs and the power.

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finance about 50% of the total project costs with low-cost debt, but in instances where lenders perceived more uncertainty as to the revenues, lenders had been willing to provide as little as 20% of the project costs.

Because Cedar Crescent was located in Texas, the permitting required for the project was minimal (as opposed to California for example, which has a very stringent and costly permitting process). The project had to file a construction permit with the exact engineering design, and consult with various environmental agencies. Wildlife, archeological, wetlands, and environmental studies had already been completed. The wildlife studies identified a number of state-listed “threatened but not endangered” species which could find the project habitat suitable.

The environmental studies confirmed that the site was formerly and currently used for oil and gas extraction. The site had a number of visible well-heads, some of which were in use, while others were “capped” and dormant. In addition to the above-ground oil and gas extraction infrastructure, there were a considerable number of underground pipes. The archeological report cited other discoveries of fossils and bones from antiquity in this part of Texas; however none had been identified at Cedar Crescent. On the southern portion of the project, there was a pile of rocks which looked like it could have once been some type of structure. Archeologists attributed the pile of rocks to an early settler’s church, but recommended no further action.

The various reports had been filed with the appropriate regulatory authorities and all but one of the necessary permits had been issued. The remaining regulatory hurdle was the Federal Aviation Administration (FAA). Prior to commencement of construction, the FAA, which governs air flight and participates in Homeland Defense, has to approve the exact location of all wind turbines. Earlier in the development process, Meltemi had acquired 100 FAA permits based on their preliminary design. However, this was done before completion the ALTA land survey, which had identified a number of previously-unknown subsurface oil and natural gas pipelines. This required relocating several turbines, and because the original design had been modified, new FAA permits were required. The FAA permit process was considered an administrative process, and it generally took 30 to 60 days after the applicant’s submission of the final turbine locations, heights and coordinates to complete. However, because a military radar installation was nearby, the Department of Defense had expressed some concerns on the prior layout, noting that wind turbines have been known to impact the effectiveness of radar, particularly on the horizon. Thus, a normally perfunctory approval was not assured.

In order to keep the project on track to meet the COD, Meltemi had reached agreement with a BOP contractor to manage and complete the on-site construction much like a builder or general contractor for a commercial real estate project. The BOP contract would take 11 months from commencement of construction to completion and the COD. The PowerGenz construction management team was led by Dennis Freeling and Curt Wong, who put together the milestone dates for the project as a reminder of how tight the schedule was ahead:

Signed agreement 12/01/2009

Acquisition Closing 12/31/2009

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Construction begins 1/1/2010

Commercial Operation Date 11/30/2010 11 months to complete

Power must flow 3/30/2011 4 months after COD

From a construction perspective this was a moderately-difficult project with considerable brush clearing and some challenging topography to manage. In order to meet the 11-month construction timetable promised by the BOP contractor, everything had to be perfect. Two components in particular concerned Freeling and Wong: 1) sometimes equipment like the turbines or transformers can have a year-long lead time from the order date to the delivery date, and 2) the interconnecting utility might not complete their portion of the work within the four months that was estimated but rather take the full 12 months allowed in the contract. Without that early interconnection, Longhorn Electric had the right to terminate the PPA.

Freeling and Wong felt that aside from the tight schedule, the biggest construction cost risk was uncovering underground snake pits, which were rumored to be home to thousands of Texas rattlers. An underground cavern could mean shipping in extra fill material, construction delays, or worse, require moving a turbine. Fortunately, a number of the turbine locations had test holes drilled, and the likelihood of encountering a massive pit was expected to be low.

Cedar Crest Mountain - FinancialsFreeling and Wong were responsible for creating two budgets for the Cedar Crescent wind development: a development budget and an operations budget. Together, they would be used to produce the financial analysis required to make the investment decision. Their budget estimates were based on their experience on three previous and now operational wind farm projects in Texas and by recent discussions with various vendors and suppliers.

The largest capital cost would be for the wind turbines. Eighteen months earlier, in April of 2008, the wind turbine market was booming and supply of turbines was tight. Concerned about being able to get turbines when they needed them, PowerGenz had put a non-refundable 35% down payment on 100 GE Energy 1.5xle wind turbines (total 150 MW). At the time they had little concern about having projects for the turbines, and although at $2.4 million per turbine the price was high, not signing the GE contract could have left them without turbines. What no one could have anticipated was the economic meltdown that occurred later in 2008. Funding for new wind projects dried up, resulting in an oversupply of older model turbines like the GE 1.5xle even as newer and more efficient models were being produced.

Although the GE 1.5xle turbines were a good fit for the Cedar Crescent development, PowerGenz had other options. The oversupply of turbines had driven down prices, and the GE turbines PowerGenz had already contracted to purchase were now selling for $1.9 million, a 21% discount to PowerGenz’s contract price. An alternate supplier, Denmark-based Vestas, sold the V80-2.0 MW turbine that was equally suitable for Cedar Crescent. The Vestas machines cost $3.1 million each and Vestas’ sales rep assured Wong that the turbines could be delivered on time if they were ordered by January 1, 2010. The Vestas V80-2.0 had a slightly higher capacity factor

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at 44% than the GE 1.5xle whose capacity factor was 43.5%, and because they were 2.0 MW, only 75 turbines would be required for Cedar Crescent versus 100 of the GE turbines. This meant fewer turbine foundations and less infrastructure, which would save money and time. Exhibit 7 contains technical information on the two wind turbines.

Freeling and Wong created the initial development budget shown below on the presumption that the GE 1.5xle turbines would be used at the $2.4 million contract price.

Cedar Crescent Mountain – Development Budget

The budget included a 2% contingency factor, which Freeling and Wong acknowledged did not account for the potential cost or risk of delays beyond the COD of November 30th.

Freeling and Wong turned their budget numbers over to Ricardo, noting that using the Vestas-2.0 turbines instead of the GE units would save about 20% of the cost Turbine Delivery and Erection costs, and about 15% of the Balance of Plant costs.

The Cedar Crescent operating budget included the following:

1. The $66/MWh price in the 20-year PPA with Lonestar.10

2. Lease payments to landowners which had been negotiated by Meltemi as a royalty- type payment equal to 6.0% of the project revenues.

3. Property taxes were easy to predict because Meltemi had negotiated a PILOT agreement with the county establishing a fixed annual payment of $250,000 for the entire 20 year term.11

4. A PTC of $21.65/MWh for the first 10-years of operation. (The PTC was a tax credit that offered PowerGenz $21.65/MWh produced, which they valued like cash).

5. Maintenance and Other Operating Expenses was a catch-all category which included the maintenance of the turbines, transformers, and transmission lines, insurance, security, etc. Annual costs were estimated at $62,000/turbine for the GE 1.5xle and $68,000/turbine for the Vestas V80-2.0 turbines. These costs were projected to increase 2% annually.

Another factor which Ricardo had to consider in his feasibility analysis was the impact of taxes. PowerGenz’s CFO had instructed Ricardo to assume a marginal corporate tax rate of 39% for all projected taxable income generated by the potential Cedar Crescent investment. With a portfolio of successful generating assets in operation and PPA contracts in place, PowerGenz produced significant annual taxable income, which could be reduced by any tax losses that might come in

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10 The 20-year term of the PPA was based on the estimated useful life of the turbines and was also the industry standard for project financial analysis.

11 Property taxes are based on the assessed value of the land and improvements thereon, and property taxes pay for local services and schools. Since the cost of these local services typically increase over time, so do property taxes. The installation of wind turbines increases the value of the property and thereby the property taxes as well. Many states, including Texas, seek to encourage renewable energy installations by allowing local taxing authorities to negotiate with IPPs to set a fixed annual property tax payment, referred to as a PILOT – Payment In Lieu of Taxes.

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the early years of the Cedar Crescent project. PowerGenz’s tax advisers had confirmed that the costs of the wind project on leased land could be depreciated on a 5-year MACRS schedule, as shown below.

YEAR 1 2 3 4 5 6MACRS % 20.0% 32.0% 19.2% 11.6% 11.6% 5.7%

Note: MACRS percentages are applied each year to the original capital cost

Decision Time

With 35 days left in the exclusivity period, the PowerGenz team needed to complete its memorandum to the company’s investment committee recommending a course of action. Ricardo and his team had already decided that Cedar Crescent Mountain was the only project worth real consideration – incomplete data, and the land assembly and permitting uncertainties in the other four Meltemi projects amounted to risks that PowerGenz’s management team was simply unwilling to take.

As Ricardo undertook the financial analysis, he noted that the CFO of PowerGenz had instructed all of the analysts at the firm to use an 8.5% hurdle rate in their evaluations. What were the other factors that he might consider? Did he have to use the contract price for the GE1.5xle turbines? Did he have to use the GE turbines at all? Were there specific conditions that PowerGenz would require be resolved by Meltemi prior to the deal closing, now just 66 days away? Were there added terms that should or could be incorporated into the contract with Meltemi? Was $15,000,000 the right price? Ricardo knew that Meltemi had a well-earned reputation as a tough negotiator so if he recommended a new price or additional conditions he had to be prepared to negotiate for those new terms or be willing to lose the contract altogether if Meltemi refused to agree to the changes.

Glossary of Acronyms

ALTA American Land Title Association, the national standard for real property surveys

BOP Balance of Plant contract or contractor

CF Capacity Factor which measures in percent the expected production of a power plant relative to its rated capacity. The rated capacity is the power the generation plant could produce if it is operating at its optimal level.

COD Commercial Operation Date

FAA Federal Aviation Administration

FERC Federal Energy Regulatory Commission, established in 1996

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IA Interconnection Agreement, between an IPP and the grid owner/operator

IPP Independent Power Producer, here like PowerGenz

ITC Investment Tax Credit

LOI Letter of Intent

LSE Load Serving Entity, in this case, Lonestar Power. LSE may also be referred to as T & D, Transmission and Distribution, companies.

MACRS Modified Accelerated Cost Recovery System, the Internal Revenue Service guidelines for depreciation adopted with the Tax Reform Act of 1986.

MW Megawatt or 1,000,000 watts is a measure of power. MW is the standard of measurement for the capacity of utility-scale electricity generation plants and capacity is the potential output of the generator when it is operating at the designed capacity. One Megawatt is the power drawn by about 600 typical homes in the U.S. A typical new coal-fired power plant is rated at 550 Megawatts.

MWh Megawatt hour or 1,000 KWh (kilowatt hours) is a measure of energy. MWh is a standard of measurement of the production of a utility-scale electricity generation facility representing the power produced over a period of time.

PILOT Payment in Lieu of Taxes, an agreement fixing property taxes

PPA Power Purchase Agreement, typically between an IPP and an LSE

PTC Production Tax Credit, a tax credit offered by the federal government to producers of renewable energy, it is based on actual MWh production and available for the first 10 years of operation.

PURPA Public Utilities Regulatory Policies Act, enacted in 1978.

RPS Renewable Portfolio Standards are regulations enacted by states requiring LSEs to use energy from renewable sources for a minimum percentage of the energy they sell to customers. This percentage typically rises gradually over time.

T & D Transmission and Distribution companies which own and maintain the power lines that deliver electricity to customers. Also referred to as LSEs or Load Serving Entities.

PowerGenz and the Meltemi Wind Energy Development Company BAB-[xxx]

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Exhibit 1Electric Power Industry Functions

Source: http://www.med.govt.nz/sectors-industries/energy/electricity/industry

Source: http://mail.nhu.edu.tw/~society/e-j/23/08.htm

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Exhibit 2

Relationship between Developers, Wholesale Producers (IPPs), Distribution Retailers (LSEs)

Exhibit 3Wholesale Power Prices

PowerGenz and the Meltemi Wind Energy Development Company BAB-[xxx]

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Exhibit 4US State Renewable Portfolio Standard (RPS) Map 2012

Exhibit 5Meltemi Energy: Portfolio of Wind Projects

PowerGenz and the Meltemi Wind Energy Development Company BAB-[xxx]

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Exhibit 6Project Map depicting required right of way (ROW)

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Exhibit 7Wind Turbine Data

GE 1.5xle

Vestas V80-2.0 MW

PowerGenz and the Meltemi Wind Energy Development Company BAB-[xxx]

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