 | | |
| x | ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | |
| o | TRANSITION REPORT UNDER SECTION 13 OR SECTION 15(d) OF THE EXCHANGE ACT |
to (Exact Name of Registrant As Specified in Its Charter)
| | |
| Delaware | 98-0493819 | |
| (State or Other Jurisdiction of Incorporation or Organization) | (IRS Employer Identification No.) |
| | |
| 26 Broadway New York NY | 10004 | |
| (Address of Principal Executive Offices) | (Zip Code) |
Registrant’s Telephone Number, Including Area Code: (212) 977-0900
Securities Registered Pursuant to Section 12(b) of the Act:
| | |
| Title of Each Class | Name of Exchange on Which Registered | |
| Common Stock, $0.001 par value | Nasdaq Stock Market, LLC |
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yeso NOx
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yeso NOx
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yesx NOo
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12-b-2 of the Exchange Act. (Check One):
| | | | |||
| Large Accelerated Filero | Accelerated Filero | Non-accelerated Filero | Smaller Reporting Companyx |
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act). Yeso NOx
The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant as of the close of business June 29, 2007 was $26,442,239. The registrant’s closing price as reported on the NASDAQ Global Markets for June 29, 2007 was $5.49 per share.
The number of outstanding shares of the registrant’s common stock as of February 29, 2008 was 13,917,347.
Documents Incorporated By Reference:Certain sections of MMC Energy, Inc.’s definitive Proxy Statement for use in connection with its 2008 annual meeting of stockholders, to be filed subsequently, are incorporated by reference into Part III of this Annual Report on Form 10-K where indicated.
i
Some of the statements under “business,” “Risk Factors,” “Management's Discussion and Analysis of Financial Condition and Results of Operations,” and elsewhere in this Annual Report on Form 10-K constitute forward-looking statements. These statements relate to future events or our strategy, future operations, future financial position, future revenues, projected costs, prospects, and the plans and objectives of management and involve known and unknown risks, uncertainties and other factors that may cause our or our industry's actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed, implied or inferred by these forward-looking statements. Such factors include, among other things, those listed under “Risk Factors” and elsewhere in this Annual Report. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “could,” “would,” “expects,” “plans,” “intends,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms and other comparable terminology.
Although we believe that the expectations reflected in the forward-looking statements are reasonable, we do not know whether we can achieve positive future results, levels of activity, performance, or goals. Actual events or results may differ materially. We undertake no obligation to update any of the forward-looking statements after the date of this Annual Report to conform those statements to reflect the occurrence of unanticipated events, except as required by applicable law.
We are an energy management company that acquires and actively manages electricity generating and energy infrastructure related assets in the United States. Our mission is to acquire, directly or through joint ventures, a portfolio of small to mid size electricity generating assets, generally below 250 megawatts, or “MW.” To date, we have acquired three electricity generating assets in California, totaling 110 MW of capacity and are in the process of upgrading two of these assets. We are also pursuing additional acquisitions of small to medium-sized power generating facilities primarily in California, Texas, the Mid-Atlantic states and the Northeastern portion of the United States. Our natural gas fueled electricity generating facilities are commonly referred to as “peaker” plants. Our plants are used to balance unexpected short term surges in demand, making them critical to the reliability, or “insurance,” of the power grids they serve. Our assets generate revenue from providing capacity and ancillary reliability services to transmission grids that distribute electricity to industrial and retail electricity providers. During peak electricity usage times, such as the summer, we also sell our electricity in the daily merchant market.
Our strategy is to create long term value by focusing on five core principles:
| • | Targeting power constrained regions |
| • | Acquiring and developing electricity generating and infrastructure related assets |
| • | Developing or restructuring acquired assets to maximize revenues |
| • | Managing risk to optimize profitability |
| • | Opportunistically partnering to develop renewable energy generating assets |
We are managed by a team of professionals with significant energy sector experience and knowledge. Our executive officers and Board of Directors have extensive experience with industry leaders in the energy and finance sectors, especially asset management, commodity pricing and risk management as well as private equity, structured finance and project finance transaction experience. We intend to leverage this extensive experience and our relationships within the energy and finance sectors to execute on our core strategy and build significant long-term value for our stockholders.
We launched our acquisition strategy in January 2006 with the acquisition of two 44 MW natural gas fired electricity generating facilities in San Diego County, one in Chula Vista and the other in Escondido, California. This acquisition provided us entry to the California wholesale electricity market. We fully re-commissioned the facilities and began earning revenues in June 2006. We acquired the formerly idle facilities for what we believe to be a discounted value to market, and believe the facilities appreciated substantially in value following their repair and re-commissioning. In November 2006, we acquired MMC Mid Sun, a 22 MW facility near Bakersfield, California, which we also successfully re-commissioned and began operating in January 2007.
The ownership of small to mid size U.S. electricity generating assets is fragmented, and we believe some of the owners and financiers of these smaller assets have experienced financial distress, which has led to a number of bankruptcies, debt restructurings, asset repossessions by lenders and asset sales. Both of these factors have created attractive buying opportunities in our strategic locations. Many assets are also held by financial investors who have relied on long-term fixed price contracts for revenues, fuel supply and operations to shield them from market and commodity risk. As these contracts expire, we expect that many owners will seek to liquidate their non-core assets. We believe additional deal flow will be derived from mergers of utilities that require divestitures in regions where the combined entity would otherwise exert excessive market power.
We believe the competition for acquiring and developing small to mid size electricity generating assets is significantly less organized and competitive, such that they can be acquired at a discount to comparable pricing for larger, well-managed assets. Institutional acquirers such as private equity firms and larger non-regulated utilities generally target larger assets because they are managing big pools of capital, requiring increased transaction sizes. Furthermore, smaller, distressed and non-contracted assets often require additional up front investment and operational restructuring, which can be unappealing to institutional buyers.
1
The electricity generating industry in the U.S. has historically been dominated by vertically integrated electric utilities with monopolistic control over franchised territories. In order to encourage more competitive wholesale electricity markets, the Public Utility Regulatory Policies Act of 1978, or “PURPA,” and the Energy Policy Act of 1992, were established. The enactment of these policies, along with a series of deregulatory policies during the 1990s, created the opportunity for the growth of Independent Power Producers, or “IPPs.”
Independent Systems Operators, or “ISOs,” and Regional Transmission Operators, or “RTOs,” were created upon the deregulation of the utility industry during the 1990s to serve as regional non-profit organizations that ensure reliable transmission system operation and to operate the energy market to foster reasonable energy costs for electricity consumers in their region. There are seven primary ISOs/RTOs in the United States, each with its own specific market rules and pricing.
As a result of this deregulation, IPPs built new generating plants and purchased existing plants from regulated utilities to market wholesale power. IPPs predominantly constructed low cost and quick-to-build natural gas fired plants, adding more than 200,000 MW in aggregate electricity capacity between 1998 and 2004. The majority of these assets were financed by banks with short-term, non-recourse debt structures. Consequently, IPPs became highly-leveraged and required substantial cash flows from these electricity generating assets to service their debt.
In 2001, wholesale electric prices began to decline from record levels primarily due to the excess capacity created by the IPPs and mild weather. By early 2002, wholesale electric prices in certain regions of the United States had dropped to their lowest levels. In California, wholesale pricing was drastically inflated in 2001 due to market manipulations by certain IPPs such as Enron, which ultimately led to bankruptcies of some utilities that were unable to pass on such inflated costs to their consumers. Emergency measures were enacted, including long term power purchase agreements backed by the California Department of Water Resources, which had sufficient credit, a $250 per MW-hour price cap, and other measures aimed at curtailing the market manipulations, served to have an immediate and drastic dampening effect on pricing. Accordingly, the cyclicality of the market was particularly felt in California. Concurrent with wholesale electricity price declines, there were sharp increases in the price of natural gas caused by increased demand from new generation facilities and starting in 2005, shrinking supply as a result of the damage to existing natural gas production facilities caused by hurricanes Katrina and Rita.
The volatility of wholesale electricity and natural gas prices led to the deterioration of the non-regulated electricity markets. As the profit margins declined, some IPPs had difficulty servicing their debt obligations, which resulted in a significant financial distress for many owners of these assets, especially smaller natural gas production facilities.
The U.S. non-regulated electricity market, or the merchant market, is now entering a period of sustained recovery. Even with increasing fuel costs, we expect that profit margins will return to sustainable levels as electricity demand increases. We believe the pace and depth of that recovery, including anticipated increases in the value of electricity generating assets and associated infrastructure driven by demand growth, will vary by asset type and region.
Some regions have recovered faster than others based on supply and demand in that region. We commonly refer to areas where electricity demand is high but electricity supply is limited due to transmission constraints and/or insufficient local capacity as “red zones.” Specifically, parts of California, Texas and the Mid-Atlantic and Northeastern United States have red zones. Red zones offer electricity generating assets the opportunity to sell services and production at premium prices. Our MMC Chula Vista and MMC Escondido facilities, for example, are located in Southern California which is one of the most constrained regions in the United States. We expect that the San Diego region will remain capacity constrained relative to other Southern California regions, excluding Los Angeles, for the foreseeable future.
The renewable electricity market in the United States is evolving and growing rapidly. According to the Department of Energy, renewable energy accounted for 94.4 gigawatts in the United States in 2004 and is
2
expected to grow to 109.6 gigawatts in 2030. In particular, wind accounted for 47% of all renewable energy in 2004, and is expected to grow to 60% in 2030, excluding hydroelectric. This trend is due primarily to state-established Renewable Portfolio Standards for minimum renewable energy production and federal Production Tax Credits, or “PTCs,” and available state credits. For example, California requires that 20% of its electricity be produced from renewable sources by 2010, New York requires 25% by 2013 and Maine has required 30% of retail sales since 2000 and thereafter as a condition of re-licensing. In addition, under current law, a federal income tax credit of 1.5 cents per kilowatt-hour, adjusted for inflation since 1992, is allowed for the production of electricity from qualified wind energy facilities and other sources of renewable energy during the 10-year period beginning on the date the facility was originally placed into service. The current value for 2007 of the credit is 2.0 cents per kilowatt-hour of electricity produced. The credit was created under the Energy Policy Act of 1992 and applies to electricity produced by a qualified wind facility placed in service after December 31, 1993, and before January 1, 2009. PTCs have been extended since the inception of the legislation and there is a general belief that these tax credits for wind generation will be extended again in the next several years. Wind is currently capturing a dominant market share of new renewable energy being developed due to a proven technology with the highest PTC, creating incentive for investors and opportunities for project debt financing.
There are three primary facility types that provide electricity to the grid: baseload, mid-merit, and peaking facilities. Baseload facilities are designed to run continuously and provide the most inexpensive electricity, and as a result provide the majority of the electricity to the U.S. transmission grid. In contrast, peaking facilities are used to balance unexpected short term surges in demand, making them critical to the reliability of the power grids they serve. Peaking facilities are costlier to run, but generally much less costly to build and maintain. Mid-merit facilities have some characteristics of both a baseload and peaker facility.
Our company targets small to mid size, less than 250 MW, natural gas fired electricity peaking generating plants in California, Texas and the Mid-Atlantic and Northeastern United States. Today, there are more than 1,500 small to mid-size natural gas-powered generating assets in the United States. The chart below shows the number of such assets located in each ISO:
| | |||
| ISO Region | Number of Assets | |||
| California (CAISO) | 468 | |||
| Texas (ERCOT) | 248 | |||
| New England (ISO-NE) | 99 | |||
| Midwest (MISO) | 213 | |||
| New York (NYISO) | 194 | |||
| Pennsylvania-Jersey-Maryland (PJM) | 261 | |||
| Southwest (SPP) | 72 | |||
Our strategy is to create long-term value by focusing on five core principles:
| • | Targeting Power Constrained Regions — We focus on regions (1) where electricity demand is high but electricity supply is limited due to transmission constraints and/or insufficient local capacity, known as “red zones,” (2) where peaker plant services can be sold at premium prices to grid operators and (3) where “natural gas is on the margin,” meaning that increases in natural gas prices can be passed on to the consumer in the form of higher electricity prices. We may also target areas with a high concentration of wind generation which have a greater reliance on peaking facilities to stabilize the transmission grid due to the intermittent nature of wind patterns. |
| • | Acquiring and Developing Electricity Generating and Infrastructure Related Assets — We target (1) acquiring and developing small to mid size clean burning natural gas electricity generating facilities (up to 250 MW) that can be purchased or developed at a discount to comparable facilities (2) companies that provide non-carbon emitting additional ancillary services and transmission grid optimization technologies. |
3
| • | Developing or Restructuring Acquired Assets to Maximize Revenues — We target electricity generating assets that often require additional development capital and re-commissioning expenditures to maximize their revenue streams. We have established a scalable platform to cost effectively develop and restructure these assets using leading industry vendors. |
| • | Managing Risk to Optimize Profitability — We believe we can optimize profitability while minimizing market-based risk through (1) contracting a substantial portion of our installed capacity and energy long-term to investment grade counterparties, (2) qualifying our facilities to provide premium ancillary services and (3) aligning our assets cost structure to correspond better to our revenue streams. |
| • | Opportunistically Partnering to Develop Renewable Energy Generating Assets — We may also (1) enter into joint ventures to develop renewable energy projects that can capitalize on the growing reliance on renewable sources of energy such as wind, and (2) acquire or develop companies that provide non-carbon emitting ancillary services and transmission grid optimization technologies. We believe wind power may be complementary to our peaking facility strategy because the inherently intermittent nature of wind creates a greater need for peaking power and ancillary services to balance fluctuations in electricity generation and to stabilize local transmission grids. |
The ownership of small to mid-size U.S. electricity generating assets is fragmented and we believe some of the owners and financiers of these smaller assets have experienced financial distress, which has led to a number of bankruptcies, debt restructurings, asset repossessions by lenders and asset sales. All of these factors have created attractive buying opportunities in our strategic locations. Many assets are also held by financial investors who have relied on long-term fixed price contracts for revenues, fuel supply and operations to shield them from market and commodity risk. As these contracts expire, we expect that many owners will seek to liquidate their non-core assets. We believe additional deal flow will be derived from mergers of utilities that require divestitures in regions where the combined entity would otherwise exert excessive market power.
We believe the competition for acquiring small to mid size electricity generating assets is significantly less organized and competitive, such that they can be acquired at a discount to comparable pricing for larger, well-managed assets. Larger, institutional acquirers such as private equity firms and larger non-regulated utilities generally target larger assets because they are managing larger pools of capital, requiring larger transaction sizes. Furthermore, smaller, distressed and non-contracted assets often require additional up front investment and significant operational restructuring, which can be unappealing to institutional buyers.
We seek to generate substantially greater investment returns on our acquisitions than those of larger baseload plants with contracted revenue streams. We believe the larger baseload plants with long term offtake contracts will result in lower rates of return than smaller peaker plants that meet our acquisition criteria. We prefer that an acquisition target sits inside congested transmission zones, as is the case with MMC Escondido and MMC Chula Vista. However, locations just outside the zone may be equally attractive depending on transmission rights, access to the zone and the purchase price.
We review each of our acquisition targets primarily based on the following factors:
| • | site location on the power transmission grid; |
| • | regulatory environment; |
| • | permitting issues and process; |
| • | feasibility studies (commercial, economic and technical); |
| • | contractual framework (terms and conditions); |
| • | risk management programs (including bonding, insurance and hedging); |
| • | potential conflicts between project participants (dispute resolution process and procedures); |
| • | estimated time to commencement and completion of implementation; |
| • | reputation, resources, experience and credit capacity of project participants; |
4
| • | offtake and supply arrangements; |
| • | likely re-commissioning period; and |
| • | potential to upgrade and/or expand the acquired site. |
Our Chula Vista and Escondido facilities, or “MMC Chula Vista” and “MMC Escondido” are located in San Diego County, California. We purchased the facilities in January 2006 from Dispersed Generating Company, LLC, an indirectly owned subsidiary of National Energy & Gas Transmission, Inc., the former non-regulated subsidiary of PG&E Corporation. Because National Energy & Gas Transmission was in the final stages of a Chapter 11 bankruptcy liquidation, the facilities were in an idle state, with virtually no maintenance for a period of two years. Accordingly, we were able to negotiate what we believe to be an attractive deep discount purchase price approximating the scrap value of the equipment. We acquired and then re-commissioned the facilities for a total cost price of approximately $5.7 million, representing a fraction of the original $57 million cost to construct the facilities in 2001.
We tested and repaired all of the key equipment, renewed all of the required operating permits, and fully re-commissioned the facilities in June 2006, in time for the critical summer market. We also executed resource adequacy capacity contracts for the balance of 2006. More recently, we executed capacity contracts covering the entire effective capacity for 2007, as well as a subsequent contract covering approximately one-half of the effective capacity for the period from 2008 to 2011.
Each facility has a gross nameplate capacity of approximately 44 MW, a heat rate (which is a measure of efficiency of converting raw fuel into electricity) in excess of 15 mmBTu/MWh (or million British Thermal units per Megawatt-hour) and is considered a “peaking facility” in that it is called to run only during periods of peak electricity demand. Each facility is equipped with two Pratt & Whitney FT4A-9 jet engines, and a spare Pratt & Whitney FT4A-9 jet engine is stored at a neighboring warehouse, for a total of five engines. These facilities also include generators, transformers, other environmental and ancillary equipment, and spare parts. MMC Escondido is situated on 1.6 acres of land owned by us. MMC Chula Vista resides on 3.8 acres subject to a long-term land lease, which expires in 2012, but is renewable at our option for up to two additional five year periods. In conjunction with the energy efficiency upgrade of MMC Chula Vista, provided we enter into a related long-term electricity purchase agreement, we have the option to extend the lease for an additional 16 years.
In November 2006, we acquired a third peaking facility located near Bakersfield, California, or “MMC Mid Sun,” for $1.25 million. In anticipation of this acquisition, in October 2006, we separately purchased an LM-2500 gas turbine at a price of $3.15 million, resulting in a total plant acquisition cost of $4.4 million. As with MMC Chula Vista and MMC Escondido, we paid what we believe to be scrap value of the equipment and a fraction of the original cost to construct the facility. This facility was also idle at the time of purchase although not in the same level of disrepair as MMC Chula Vista and MMC Escondido.
We tested and repaired all of the key equipment, renewed all of the required operating permits, and successfully re-commissioned the facilities in January, 2007, approximately 70 days after closing on the purchase. We also executed resource adequacy capacity revenue contracts for the balance of 2007. As of February 29, 2008, resource adequacy contracts for approximately three quarters of the effective capacity for the period from 2008 to 2011 were executed.
The facility has a gross nameplate capacity of approximately 22 MW, a heat rate of approximately 12 mmBTu/MWh, and is powered by a General Electric LM-2500 gas turbine. The facility also includes a generator, transformer, other environmental and ancillary equipment, and spare parts. MMC Mid-Sun resides on approximately two acres subject to a long-term land lease, which expires in 2016, but is renewable at our option for an additional five year period.
5
MMC Chula Vista was originally developed with a view towards supporting two distinct generating units, and presents an attractive expansion opportunity. We plan to implement an energy efficiency upgrade of the facility with two General Electric LM-6000 turbines and related equipment. We estimate this energy efficiency upgrade will cost in excess of $80 million. We expect the new facility to have up to 49 MW of additional capacity, on top of the 44 MW of existing capacity, and will be more efficient, requiring less natural gas to produce one MW of electricity, which should serve to greatly increase the opportunities to sell electricity. The new turbines will be equipped with advanced air pollution control systems including Selective Catalytic Reduction for the control of oxides of nitrogen, and an Oxidation Catalyst for the control of carbon monoxide. Overall, the new plant will be more fuel efficient, produce more power than the existing turbines, and be less polluting on a per megawatt-hour basis. The upgraded facility will also be designed to qualify for capacity and for ancillary services, during off-peak hours, as well. Furthermore, we believe it may be possible to expand on the MMC Chula Vista facility with minimal impact on the existing electricity generating capabilities, allowing the existing facility to run and generate revenues during most of the targeted construction period. To date, we have completed an initial engineering feasibility study and San Diego Gas & Electric has completed its transmission line impact study. We have also begun the process of preparing the detailed engineering specifications to use for construction bids and we have filed the required permitting applications with the city of Chula Vista. During the fourth quarter of 2007 the California Energy Commission, or the “CEC,” accepted our Application for Certification for the Chula Vista Energy Upgrade Project.
With its acceptance of the application, the CEC Staff signaled its agreement that the application contains information sufficient for its review of engineering aspects and environmental effects of the project. This formally begins the California power plant site certification process. Under this process, it is expected that the project would be granted a construction license approximately one year from the date of the application's acceptance. In January 2008 we agreed to purchase two LM-6000 PC Sprint natural gas-fired turbines from GE Packaged Power, Inc, a subsidiary of General Electric, to be used in this project. The total purchase price for the turbines is approximately $31 million, to be paid in several installments through the expected delivery date in early 2009. The turbines are the primary equipment to be used in the project. The company opted to purchase the LM-6000 units from General Electric after it was unable to find such unit on the open market.
Our MMC Escondido facility may also be upgraded with similar General Electric equipment, or potentially next generation technology. We have filed a permit application with the San Diego Air Pollution Control District, or the “SDAPCD,” to upgrade the facility. The upgrade will consist of the removal of the existing 44 MW Pratt and Whitney Twin Pac combustion turbines along with their support and control systems, and replacing them with a single 46.5 MW General Electric LM-6000 new technology aero-derivative combustion turbine. The new turbine will be equipped with advanced air pollution control systems including Selective Catalytic Reduction for the control of oxides of nitrogen, and an Oxidation Catalyst for the control of carbon monoxide. Overall, the new plant will be more fuel efficient, produce more power than the existing turbines, and be less polluting on a per megawatt-hour basis. The upgraded facility will also be designed to qualify for capacity and for ancillary services, during off-peak hours, as well. According to the transmission interconnection agreement with SDG&E, we have appropriate transmission capacity to perform the efficiency upgrade. We have engaged environmental consultants to arrange timely approval of all required permits, as well as Worley Parsons as “owners engineer” to consult on the development of the project.
MMC Mid-Sun, which we acquired in November, 2006, was originally built as a co-generating facility, providing both steam and electricity, and has the potential to be expanded as such. The MMC Mid-Sun facility is surrounded by producing oil fields, which require steam to be pumped into the wells to increase yield. As the recent surge in oil prices has compelled further development of the area’s oil production, we believe the time may be right to explore such an upgrade. We have begun preliminary discussions with one major producer interested in a long-term contract to provide steam, as well as electricity, which may support the cost of the upgrade.
6
Independent Service Operators, or “ISOs,” were created upon the deregulation of the utility industry to serve as regional non-profit organizations to ensure reliable transmission system operation and operate the energy market to foster reasonable energy costs for electricity consumers in their region. For consumers, the ISO ensures that their electrical needs are met around-the-clock at a reasonable price. For energy companies, the ISO ensures equal access to transmission lines. The ISO never buys or sells electricity for its own account but instead acts as an electronic auction house to match supply with demand. Most sales in California are pursuant to bilateral contracts, but a significant percentage is sold in an energy market. ISOs are arranged geographically, and the map below shows which US regions are served by which ISO. The California Independent System Operators, or “CAISO,” serves the California market, which is the market in which we currently operate and which will be a source of potential growth for us.
Target regions outside of California are managed by different ISOs, including:
| | |
| Region | ISO | |
| New England | ISO – New England or “NEPOOL” | |
| New York | New York ISO | |
| Mid-Atlantic | PJM Interconnect | |
| Texas | ERCOT |
Each of these ISOs has a very similar mandate as the CAISO, and is subject to the Federal Energy Regulatory Commission, or FERC, jurisdiction. However, each operates independently with its own set of market rules and pricing.
The CAISO Energy Market operates much like a stock exchange, with market participants establishing a price for electricity by matching supply and demand. The Energy Market consists of Day-Ahead and Real-Time Markets. The Day-Ahead Market is a forward market in which hourly prices are calculated for the next operating day based on generation offers, demand bids and scheduled bilateral transactions. The Real-Time Market is a spot market in which current prices are calculated at five-minute intervals based on actual grid operating conditions. In both the Day-Ahead and Real-Time markets, CAISO runs the bids to arrive at a market clearing price by aggregating the lowest bids available until the required capacity is available. All successful bidders are then paid for their energy at this market clearing price upon delivery of the electricity at the times specified. The CAISO schedules transmission transactions, arranges for necessary ancillary services and administers a real-time balancing energy market. The market clearing price is subject to a $400/MW per hour cap imposed by the California Public Utilities Commission, or “CPUC.”
On a long-term basis, the CAISO has indicated its intent to adopt a locational, or nodal, pricing model similar to that of PJM Interconnection, which is the ISO for the mid-Atlantic region. In such a model, the market clearing prices for the larger region, which in our case is Southern California excluding Los Angeles, or “SP-15” as known to CAISO, are adjusted up or down on a micro-regional basis based on the supply/ demand and transmission constraints applicable to the particular sub-region. We expect that the San Diego region will remain capacity constrained relative to other SP-15 regions over the next ten years. We expect the locational pricing to be beneficial to us once enacted.
In addition, owners of non-hydroelectric generation in California, including certain of our facilities, must offer to keep their generation on-line and stand ready to offer power into the CAISO’s spot markets if the output is not under contract or scheduled for delivery within the hour, unless granted a waiver by the CAISO. This is known as the “must-offer requirement”. The practical effect of this rule is to allow the CAISO, and by extension the utilities and other load serving entities in the market, to obtain operating reserves without paying for them, and to release excess supply energy into the market, thus depressing prices. On August 26, 2006, the Independent Energy Producers, a trade association, filed a complaint at the FERC, requesting that the FERC require the CAISO to implement a Reliability Capacity Services Tariff, or RCST, that would pay generators for the capacity obtained pursuant to the must-offer requirement. If granted by the FERC, the new RCST may result in increased capacity revenue opportunities for generators.
The CPUC has issued a series of orders purporting to require exempt wholesale generators and other power plant owners to comply with detailed operation, maintenance and logbook standards for electricity
7
generating facilities. The CPUC has adopted detailed reporting requirements for the standards, and conducts frequent on-site spot inspections and more comprehensive facility audits to evaluate compliance. The CPUC’s efforts to implement and enforce the operation, maintenance and logbook standards could interfere with our future ability to make economic business decisions regarding our units, including decisions regarding unit retirements, and could have a material adverse impact on our business activities in California.
Our three facilities described above are considered “peaking facilities” that typically run only during periods of peak demand. Peaking facilities are by nature costlier to run per MWh of electricity produced, but generally much less costly to build and maintain as compared to “baseload” facilities which provide cheaper electricity and are run continuously. Despite being costlier to run, peaking facilities are also less sensitive to commodity pricing as our facilities will generally run only in an emergency when pricing is at a significant premium. We believe that peaking facilities will become more critical with the emergence of renewable electricity sources, such as wind, which by nature is subject to very short term fluctuations in output.
Peaking facilities typically provide spinning and non-spinning reserve and resource adequacy capacity services. These services currently represent our primary revenue stream. We are able to operate our facilities profitably on these services alone due to relatively low fixed operating costs and the discounted purchase price we paid to acquire these facilities (when compared to the original cost of building such facilities).
For our facilities, managing the setting of daily trading strategies to provide electricty and ancillary services is critical. We set trading strategies based on market conditions and the specific operating characteristics of each individual plant. We rely on our relationship with Bear Energy L.P., a subsidiary of The Bear Stearns Companies, Inc., to provide access to its trading desk to execute on the strategy. Given our size, it is more efficient to outsource trading activities which must be covered on a daily basis. The Bear Energy traders have full access to our markets and are able to execute on trades on a real-time basis in order to optimize our revenues. In order to properly align interests, Bear Energy receives a significant percentage of any revenues they are able to generate above the profit targets set in advance with us. This trading capability remains vital even if an asset is hedged. There is generally an ability to generate revenues beyond what is required to be passed onto the hedge counterparty which is generally set based on general index pricing.
One source of revenue is installed capacity revenue, which is available to all generators in California. Effective June 1, 2006, the CPUC requires that each electricity provider serving customers in California reserve sufficient electricity generating capacity to cover 115% of its expected peak demand. This requirement is generally satisfied by any contracts the utility already has in place directly with generators or through CAISO sponsored programs.
For any remaining shortfall, the utility must find additional generators not already contracted, to enter into Resource Adequacy, or “RA,” contracts. Such RA contracts simply link the generator to the retail provider on an exclusive basis strictly for purposes of meeting this requirement. RA contracts do not bind the generator to provide electricity or other services exclusively to the counterparty, or in any way inhibit the generator from earning other market-based revenues. However, the generator is obligated to bid its energy into the CAISO markets on a daily basis such that its capacity is available to CAISO if needed, at the generator’s bid price.
The MMC Chula Vista and MMC Escondido facilities each sold forward 35.5 MW, the effective summer rating, of RA capacity from August through December 2006 and, under a new contract, for 2007. In addition, we have signed RA contracts for 55% of the Net Qualified Capacity of our existing generation portfolio from 2008 through 2011.
Ancillary services are the provision of reserve energy generating capacity that is available to be dispatched when there is a sharp rise in demand for electricity. This capacity can be bought, sold and dispatched within seconds, minutes or hours. The primary ancillary services are procured by the CAISO daily in Day-Ahead Markets.
8
The three primary ancillary services are:
| • | Spinning Reserves: Power plants that are already on-line, defined as the generator is running and synchronized to the grid, with additional capacity that is capable of ramping over a specified range within ten minutes and running for at least two hours. |
| • | Non-spinning Reserves: Power plants that are available but not on-line, defined as the generator is not running and synchronized to the grid, but capable of being synchronized and ramping to a specified level within ten minutes, and running for at least two hours. |
| • | Regulation: Power plants that are already synchronized with the power grid and that can be increased or decreased instantly to keep energy supply and energy use in balance. |
We seek to qualify our current facilities with the CAISO for spinning reserve services and to contract for installed capacity revenues either through the CAISO or directly with investment grade third parties.
In the event of an immediate, or ten minute, demand for electricity, the CAISO will pay market-based clearing prices to the spinning reserve facility regardless of whether the facility is called upon to provide additional electricity. However, if the facility is called upon to provide electricity, the CAISO will pay the market clearing price for the spin service, or the “capacity price” in addition to purchasing the actual electricity provided at the greater of cost or market price, referred to as the “energy price,” as described in “Revenues from Electricity Sales” below.
In addition to spinning reserves, there is a market for non-spinning reserves, which have provided a lower premium to non-spinning reserves. However, should this trend reverse, we have the ability to provide this service in lieu of spinning reserves.
On October 9, 2007, Bear Energy notified us that it was suspending bidding spinning reserve services into the CAISO system for our three facilities, effective October 10, 2007, due to the uncertain regulatory environment surrounding our provision of these services. The facilities are currently certified to provide spinning and non-spinning reserves to the CAISO system. Consequently, we began to bid exclusively non-spinning reserves into the CAISO system, a similar but lower priced ten minute power ancillary service, critical to the reliability of the CAISO system. On June 4, 2007 the CAISO issued a white paper which called into question our facilities’ qualification to provide spinning reserves. On September 20, 2007, the CAISO issued an amendment to this white paper which more narrowly focused regulatory uncertainty on the spinning reserve services provided by facilities configured similar to our facilities.
As non-spinning reserve service has historically priced lower than spinning reserve service and this trend can be expected to continue, we expect that continued suspension of bidding spinning reserve services could have a material adverse effect on our results from operations.
Our facilities’ spinning reserve certification remains in effect. We are pursuing the matter vigorously, as advised by our FERC counsel, to remove the uncertainty surrounding this status with a view toward allowing Bear Energy to resume bidding spinning reserves. There can be no assurance we will be successful in these efforts.
Electricity sales represent the provision of electricity to a local power grid through Day-Ahead and Real-Time auctions managed by the ISO, the “merchant market”, or bilateral agreements with a direct counterparty.
Aside from bilateral contracts, which we may enter into from time to time, we generally offer our energy to the ISO daily at its variable cost plus a desired margin. In a merchant market, our facilities can only be dispatched if the market clearing price exceeds our bid price. The difference between the market clearing price and the cost of fuel to generate electricity is commonly referred to as the spark spread. We may also receive out of merit dispatches. This occurs when our electricity is needed locally due to local transmission constraints, in which case we will be paid our bid price for energy provided.
9
Our operations are subject to extensive regulation by governmental agencies. FERC is the U.S. federal agency with jurisdiction over interstate electricity sales, wholesale electric rates, hydroelectric licensing, natural gas pricing, and oil pipeline rates. The FERC also reviews and authorizes liquefied natural gas terminals, interstate natural gas pipelines and non-federal hydropower projects. Our facilities are subject to energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the ownership and operation of our facilities, and the use of electric energy, capacity and related products, including ancillary services. Federal laws and regulations govern, among other things, transactions by and with purchasers of electricity, including utility companies, the operation of a power plant and the ownership of a power plant. Under limited circumstances where exclusive federal jurisdiction is not applicable or specific exemptions or waivers from state or federal laws or regulations are otherwise unavailable, federal or state utility regulatory commissions may have broad jurisdiction over non-utility owned electric power plants. Energy-producing projects are also subject to federal, state and local laws and regulations that govern the geographical location, zoning, land use and operation of a project. Federal, state and local environmental requirements generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy-producing facility and that the facility then operate in compliance with these permits and approvals.
The FERC has ratemaking jurisdiction and other authority with respect to interstate wholesale sales and transmission of electric energy, other than transmission that is “bundled” with retail sales, under the Federal Power Act and with respect to certain interstate sales, transportation and storage of natural gas under the Natural Gas Act of 1938. The enactment of the Public Utility Regulatory Policies Act of 1978, or PURPA, and the adoption of regulations under PURPA by the FERC provided incentives for the development of cogeneration facilities and small electricity production facilities using alternative or renewable fuels by establishing certain exemptions from the Federal Power Act.
A comprehensive energy bill was passed by the U.S. House and Senate in July 2005 and was signed by President Bush on August 8, 2005. Known as “EPAct 2005,” this comprehensive legislation includes provisions for merger review reform, for the introduction of new regulations regarding “Transmission Operation Improvements,” for transmission rate reform, for incentives for various generating technologies and for the extension through December 31, 2007 of production tax credits for wind and other specified types of generation.
The FERC has finalized rules to implement the enactment of the Public Utility Holding Company Act of 2005, or the PUHCA 2005. PUHCA 2005 is primarily a “books and records access” statute and does not give the FERC any new substantive authority under the Federal Power Act or Natural Gas Act. The FERC has also issued final rules to implement the electric company merger and acquisition provisions of EPAct 2005.
The Federal Power Act grants the FERC exclusive jurisdiction over the rates, terms and conditions of wholesale sales of electricity and transmission services in interstate commerce, other than transmission that is “bundled” with retail sales, including ongoing, as well as initial, rate jurisdiction. This jurisdiction allows the FERC to revoke or modify previously approved rates after notice and opportunity for hearing. These rates may be based on a cost-of-service approach or, in geographic and product markets determined by the FERC to be workably competitive, may be market-based. Most qualifying facilities, as that term is defined in PURPA, are exempt from the ratemaking and several other provisions of the Federal Power Act. Exempt wholesale generators certified in accordance with the FERC’s rules under PUHCA 2005 and other non-qualifying facility independent power projects are subject to the Federal Power Act and to the FERC’s ratemaking jurisdiction thereunder, but the FERC typically grants exempt wholesale generators the authority to charge market-based rates to purchasers which are not affiliated electric utility companies as long as the absence of market power is shown. In addition, the Federal Power Act grants the FERC jurisdiction over the sale or transfer of jurisdictional facilities, including wholesale electricity sales contracts and, after EPAct 2005, generating facilities, and
10
in some cases, jurisdiction over the issuance of securities or the assumption of specified liabilities and some interlocking directorates. In granting authority to make sales at market-based rates, the FERC typically also grants blanket approval for the issuance of securities and partial waiver of the restrictions on interlocking directorates.
Our facilities are subject to the FERC ratemaking regulation under the Federal Power Act. Our future facilities are also likely to be subject to the FERC jurisdiction on rates.
Our facilities use natural gas as their primary fuel. Under the Natural Gas Act of 1938, the FERC has jurisdiction over certain sales of natural gas and over transportation and storage of natural gas in interstate commerce. The FERC has granted blanket authority to all persons to make sales of natural gas without restriction but continues to exercise significant oversight with respect to transportation and storage of natural gas services in interstate commerce.
Generally, projects that sell electricity to wholesale purchasers other than the local utility to which the project is interconnected require the transmission of electricity over power lines owned by others. This transmission service over the lines of intervening transmission owners is also known as wheeling. The prices and other terms and conditions of transmission contracts are regulated by the FERC when the entity providing the transmission service is a jurisdictional public utility under the Federal Power Act.
The Energy Policy Act of 1992 laid the groundwork for a competitive wholesale market for electricity by, among other things, expanding the FERC’s authority to order electric utilities to transmit third-party electricity over their transmission lines, thus allowing qualifying facilities under PURPA, electricity marketers and those qualifying as exempt wholesale generators to more effectively compete in the wholesale market.
In 1996, the FERC issued Order No. 888, also known as the Open Access Rules, which require utilities to offer eligible wholesale transmission customers open access on utility transmission lines on a comparable basis to the utilities’ own use of the lines and directed jurisdictional public utilities that control a substantial portion of the nation’s electric transmission networks to file uniform, non-discriminatory open access tariffs containing the terms and conditions under which they would provide such open access transmission service. The FERC subsequently issued Order Nos. 888-A, 888-B and 888-C to clarify the terms that jurisdictional transmitting utilities are required to include in their open access transmission tariffs and Order No. 889, which required those transmitting utilities to abide by specified standards of conduct when using their own transmission systems to make wholesale sales of electricity, and to post specified transmission information, including information about transmission requests and availability, on a publicly available computer bulletin board.
We are subject to environmental regulation by federal, state and local authorities. We believe that our facilities are in substantial compliance with environmental regulatory requirements. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, future proceedings that may be initiated by environmental authorities, and settlements agreed to by other companies could affect the costs and the manner in which we conduct our business, and may also cause us to make substantial additional capital expenditures. We may not be able to recover these increased costs from our customers and our financial position and results of operations may be materially adversely affected as a result.
Typically, environmental laws and regulations require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a project or generating facility. Meeting all the necessary requirements can delay or sometimes prevent the completion of a project, as well as require extensive modifications to projects, which may involve significant capital expenditures.
Mercury Regulation. The Clean Air Mercury Rule, or CAMR, published in the Federal Register on May 18, 2005, creates a market-based cap-and-trade program to reduce nationwide utility emissions of mercury in two distinct phases. In the first phase of the program, which will come into effect in 2010, the annual
11
nationwide cap will be 38 tons. Emissions of mercury are to be reduced primarily by taking advantage of mercury reductions achieved by reducing sulfur dioxide and nitrous oxide emissions under the CAMR. In the second phase, which is to take effect in 2018, coal-fired power plants will be subject to a lower annual cap, which will reduce emissions nationwide to 15 tons. States may join the trading program by adopting the CAMR model trading rule in state regulations, or they may adopt regulations that mirror the necessary components of the model trading rule. States are not required to adopt a cap-and-trade program and may promulgate alternative regulations, such as command and control regulations, that are equivalent to or more stringent than the CAMR’s suggested cap-and-trade program. Any program adopted by a state must be approved by the United States Environmental Protection Agency, or US EPA.
Contemporaneous with the adoption of the CAMR, the US EPA rescinded its previous finding that mercury emissions from coal-fired power plants had to be regulated as a hazardous air pollutant pursuant to Section 112 of the federal Clean Air Act, which would have imposed technology-based standards. Litigation has been filed challenging the US EPA’s rescission action and claiming that the agency should have imposed technology-based limitations on mercury emissions instead of adopting a market-based program. Litigation was also filed to challenge the CAMR. As a result of these challenges, the CAMR rules and timetables may change.
If California implements the CAMR by adopting a cap-and-trade program for achieving reductions in mercury emissions, we may have the option to purchase mercury emission allowances, to install pollution control equipment, to otherwise alter our planned operations to reduce mercury emissions, or to implement some combination thereof.
National Ambient Air Quality Standards. Ambient air quality standards for ozone and fine particulate matter were adopted by the US EPA in July 1997. The US EPA designated non-attainment areas for the 8-hour ozone standard on April 30, 2004, and for the fine particulate standard on January 5, 2005. Our facilities are located in counties that have been identified as being in non-attainment with both standards. States are required to revise their implementation plans for the ozone and particulate matter standards within three years of the effective date of the respective non-attainment designations. The revised state implementation plans are likely to require additional emission reductions from facilities that are significant emitters of ozone precursors and particulates. Any additional obligations on our facilities to further reduce their emissions of sulfur dioxide and nitrous oxide and fine particulates to address local non-attainment with the 8-hour ozone and fine particulate matter standards will not be known until the states revise their implementation plans. Depending upon the final standards that are adopted, we may incur substantial costs or experience other financial impacts resulting from required capital improvements or operational changes.
As of February 29, 2008 we had six full-time employees who are located in our executive offices in New York, New York, and one additional employee in California. None of our employees are represented by labor unions and we consider our employee relations to be good.
Our existing facilities have no direct employees and primary operations, including Energy Management and Operations & Maintenance, are fully contracted-out to third parties at competitive rates, and overseen by our executive team. Upon expiration of their initial terms, Energy Management and Operations & Maintenance services will be put to bid among several firms with which we have strong relationships. Under our current operations and maintenance contract, four full time workers man our facilities during peak hours and two during off-peak periods.
We were originally incorporated in Nevada under the name High Tide Ventures, Inc. on February 13, 2003. On May 3, 2006, High Tide changed its name to MMC Energy, Inc. On May 15, 2006, a wholly-owned subsidiary of MMC Energy, Inc. merged with and into MMC Energy North America LLC, a Delaware limited liability company, the survivor of which merger was MMC Energy North America LLC. Pursuant to the merger, the former members of the limited liability company received shares of MMC Energy, Inc. in exchange for their equity interests in such company and the limited liability company became a wholly-owned subsidiary of MMC Energy, Inc. Prior to this merger, MMC Energy North America LLC, which began operations in February 2005, acquired the electricity generating facilities located in Chula Vista and Escondido,
12
California and otherwise conducted our current business as described throughout this report. As a result of the merger, MMC Energy, Inc. thus acquired the business of MMC Energy North America LLC, including the electricity generating facilities. On September 22, 2006, we reincorporated as a Delaware corporation by means of a merger of the existing Nevada corporation with and into MMC Energy, Inc., a newly-formed Delaware corporation. On April 19, 2007, we effected a one-for-ten reverse stock split of our common stock. On July 1, 2007 we successfully listed our shares of common stock for trading on the NASDAQ Global Market.
Not Applicable.
Not Applicable.
Our facilities consist of three electricity generating facilities located in Chula Vista, Escondido and Bakersfield, California. The MMC Chula Vista and MMC Escondido facilities have a gross nameplate capacity of approximately 44 MW each and the Bakersfield facility has a gross nameplate capacity of approximately 22 MW. Each facility is considered a “peaking facility” in that it is called to run only during periods of peak electricity demand. Our facility located in Escondido is situated on 1.6 acres of land owned by us. Our facility located in Chula Vista resides on 3.8 acres, which we lease pursuant to a lease that expires in 2012, renewable at our option for up to two additional five year periods. The Bakersfield facility is located on approximately two acres, which we lease pursuant to a lease that expires in 2016, renewable at our option for an additional five year period.
We lease our principal executive office located at 26 Broadway, Suite 960, New York, New York, 10004. The office, consisting of approximately 2,500 square feet of space, is suitable to accommodate our space requirements for at least the next twelve months. The lease for this office expires December 31, 2010. Our average monthly rent over the term of the lease for our principal executive office is approximately $9,000.
From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business. We currently are not aware of any such legal proceedings that we believe will have, individually or in the aggregate, a material adverse affect on our business, financial condition or operating results.
At our annual meeting of stockholders held on October 17, 2007, two proposals were voted upon by our stockholders. A description of each proposal and a tabulation of the votes for each of the proposals can be found in our Quarterly Report Form 10-QSB filed on November 8, 2007.
In accordance with our by-laws, our stockholders are hereby notified that the Annual Meeting of Stockholders of MMC Energy, Inc. will he held on Wednesday, May 28, 2008.
13
Our common stock began trading publicly on the OTCBB on May 15, 2006 under the symbol “MMCY.OB.” Prior to May 15, 2006, trades in our common stock were in the shares of a public company with which we merged on that date. On July 3, 2007 in connection with our recently consummated public offering of common stock, our common stock began trading on the NASDAQ Global Market under the symbol “MMCE.” The following table sets forth the high and low prices of our common stock, as reported by the NASDAQ Global Market, since July 3, 2007 and the high and low bid quotations of our common stock as reported by the OTCBB for the periods prior to July 3, 2007. OTCBB quotations reflect prices between dealers and do not include retain mark-ups, mark-downs, and commissions and may not necessarily represent actual transactions.
| | | ||||||
| High | Low | |||||||
| Fiscal 2007 | ||||||||
| Fourth Quarter | $ | 4.85 | $ | 2.92 | ||||
| Third Quarter | 9.75 | 5.80 | ||||||
| Second Quarter | 5.50 | 3.75 | ||||||
| First Quarter | 11.60 | 6.20 | ||||||
| Fiscal 2006 | ||||||||
| Fourth Quarter | $ | 24.00 | $ | 6.20 | ||||
| Third Quarter | 30.00 | 19.70 | ||||||
| Second Quarter | 34.00 | 12.00 | ||||||
| First Quarter | — | — | ||||||
As of February 29, 2008, there were approximately 1,492 holders of record of our common stock.
Since May 15, 2006, no dividends have been paid by us to our equity holders, and to our knowledge no dividends were paid by High Tide to its equity holders prior to the merger. We intend to retain earnings, if any, to support the development of the business and therefore do not anticipate paying cash dividends for the foreseeable future. In addition, we currently are restricted from paying dividends under the terms of our lending facility. Payment of future dividends, if any, will be at the discretion of our board of directors after taking into account various factors, including current financial condition, operating results and current and anticipated cash needs.
Below is a table summarizing all equity security issuances under our equity compensation plans previously approved by our security holders:
| | | | |||||||||
| Number of Securities to Be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a) | Weighted-Average Exercise Price of Outstanding Options, awarrants and Rights (b) | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c) | ||||||||||
| 2006 Equity Incentive Plan | 93,000 | $ | 9.29 | 388,164 | ||||||||
| Total | 93,000 | $ | 9.29 | 388,164 | ||||||||
Securities remaining available for issuance also reflects issuance of 18,836 restricted stock as compensation to directors and employees more fully described in Note 7 to our consolidated financial statements included in Item 8 of this annual report. Currently, there are no compensation plans in effect under which our equity securities are authorized for issuance that were adopted without the approval of security holders.
During the year ended December 31, 2007 we did not repurchase any shares as part of any publicly announced plans or programs or otherwise.
Not Applicable.
14
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and notes thereto appearing in this Annual Report and in our other public filings. This discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors. See “Forward Looking Statements” on page 3 of this Annual Report.
We are an energy company that acquires and actively manages electricity generating and energy infrastructure related assets in the United States. Our mission is to acquire a portfolio of small to mid-size electricity generating assets, generally below 260 MW. In addition to electricity, these assets can provide capacity and ancillary services. To date, we have acquired three electricity generating assets in California, totaling 110 MW of capacity. We are currently in the process of upgrading two of these assets. We are also pursuing additional acquisitions primarily in California, Texas and the Mid-Atlantic and Northeastern United States.
Our strategy is to create long-term value by focusing on five core principles:
| • | Targeting transmission and electricity constrained regions |
| • | Acquiring, developing and operating electricity generating and infrastructure related assets |
| • | Restructuring acquired assets to maximize revenues |
| • | Managing risk to optimize profitability |
| • | Opportunistically partnering to develop renewable energy generating assets |
We are managed by a team of professionals with significant energy sector experience and knowledge. Our executive officers and Board of Directors have extensive experience with industry leaders in the energy and finance sectors, especially asset management, commodity pricing and risk management as well as private equity, structured finance and project finance transactional experience. We intend to leverage this extensive experience and our relationships within the energy and finance sectors to execute on our core strategy and build significant long-term value for our stockholders.
We launched our acquisition strategy in January 2006 with the acquisition of MMC Chula Vista and MMC Escondido, each of which is a 44 MW natural gas-fired generating facility located in San Diego County, California. This acquisition provided us entry to the California wholesale power and electricity market. We fully re-commissioned the facilities and began earning revenues in June 2006.
On July 3, 2007, we listed our common stock on the NASDAQ Global Market in connection with the closing of a $50 million underwritten public offering of our common stock.
We currently have six full time employees based at our headquarters in New York, New York and one additional employee based in California. We have contracted for third party labor for on-site operations and maintenance of our existing facilities, as well as energy management and trading support. We expect to manage any future facilities acquired in a similar fashion. To support our future growth plans, we expect to hire additional professional staff, particularly in our New York office, to support increased acquisition activity and asset management responsibilities.
Our consolidated financial statements are prepared in accordance with accounting principals generally accepted in the United States. The preparation of our financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, costs and expenses, and related disclosure. We base our estimates and assumptions on historical experience and on various other assumptions that we believe to be
15
reasonable under the circumstances; however, our operating experience is limited. Future events, however, may differ markedly from our current expectations and assumptions. While there are a number of significant accounting policies affecting our consolidated financial statements, we believe the following critical accounting policies involve the most complex, difficult and subjective estimates and judgments:
We recognize revenue when all of the following circumstances are satisfied: (1) persuasive evidence of an arrangement exists, (2) price is fixed or determinable, (3) collectibility is reasonably assured, and (4) delivery has occurred. Revenues are recognized upon delivery of energy or services. The revenues we collect for ancillary services and energy delivery fluctuate based on market prices established by CAISO on a daily, hourly and real-time basis.
We recognize energy production revenue when energy has been substantially transmitted to the customer. We recognize revenue when electricity is delivered to a customer pursuant to contractual commitments that specify volume, price and delivery requirements. Some sales of energy are based on economic dispatch, or “as-ordered,” by an independent system operator, or “ISO,” based on member participation agreements, but without an underlying contractual commitment. Revenues for sales of energy based on ISO dispatches are recorded on the basis of MW-hours delivered, at the applicable wholesale market prices. In addition to bilateral contracts that we may enter into from time to time, we generally offer our energy to the ISO daily at its variable cost to produce plus a desired minimum profit margin. Our facilities can be dispatched only if the market clearing price exceeds our bid price. We may also receive “out of merit” dispatches in times when the market price is less than our bid price, but our electricity is needed locally due to local transmission constraints, in which case we will be paid our bid price for energy provided.
As described under “Results of Operations” below, we also recognize revenues from the provision of ancillary services and under capacity contracts. Although there are several types of ancillary services, to date we primarily provide “spin” and “non spin” services, which call for the facilities to be delivering the awarded capacity within 10 minutes of dispatch whether already connected to the grid (spin) or not (non-spin). We recognize these revenues at the time of dispatch by the ISO. Capacity (resource adequacy) contract revenues are recognized based on the facility's capacity as certified by the California Public Utility Commission, or CPUC, and by CAISO.
Our electricity generating facilities are generally referred to as “‘peaker” plants. Peaker plants are used to balance unexpected short term surges in electricity demand, making them critical to the reliability, or “insurance,” of the transmission grids they serve. Our revenues to date have been earned by providing resource adequacy capacity, ancillary services and energy production, as described more fully below under “Results of Operations”.
Since we commenced our operations on October 27, 2006 and were considered a development stage enterprise until June 12, 2006, comparisons of periods in 2006 with corresponding periods in 2007 for our of results of operations are not meaningful.
Our revenues consist of energy production, ancillary services, and resource adequacy capacity revenues.
| • | Resource Adequacy Capacity — Regulatory capacity payments for generators of any type are based strictly on total installed capacity measured in MW. In the California market where we currently operate exclusively, market-based capacity revenues are earned through resource adequacy contracts, whereby the counterparty can point to the our facilities' installed capacity as a source to supply its peak demand plus a mandatory safety margin as dictated by the California Public Utilities Commission, or “CPUC.” The contract does not create an obligation to supply electricity to the counterparty, but does obligate us to bid its energy into the CAISO markets on a daily basis such that our capacity is available to the CAISO, if needed, at our price. The resource adequacy capacity |
16
| amount cannot exceed the qualified capacity amount for the resource. Qualified capacity is certified by CAISO. For 2006, the MMC Escondido and MMC Chula Vista facilities were certified by CAISO and the CPUC for 40 MW each, and for 2007, 35.5 MW each and MMC Mid-Sun for 22 MW. |
| • | Ancillary Services — Although there are several types of ancillary services, we primarily provide “spin” and “non-spin” services which call for the facilities to be delivering the awarded capacity within 10 minutes of dispatch whether already synchronized to the grid (spin) or not (non-spin). Spin services typically offer higher rates. As of October 9, 2007, Bear Energy, our scheduling coordinator advised us that it would no longer bid our facilities into the spin services market due to regulatory uncertainty concerning our spin qualification with CAISO. Furthermore, pricing for non-spin reserves has been negligible since October, 2007. While we expect pricing to recover somewhat during the peak Summer period, our ancillary service revenues will likely not be as large a percentage of our total revenues as they have been historically. |
| • | Energy Production — We provide electricity to a local power grid through day ahead and real time auctions managed by the CAISO, the “merchant market” or through financial settled bilateral agreements with a utility or other direct counterparty. As we have no outstanding electricity purchase agreements or other contracted energy production, all of our energy production revenues are earned in the daily merchant market. |
Revenues for the year ended December 31, 2007 and 2006 were $6,729,514 and $3,643,324, respectively, and were distributed as follows:
| | | ||||||
| Years Ended December 31, | 2007 | 2006 | ||||||
| Operating Revenues: | ||||||||
| Resource adequacy capacity | $ | 3,066,000 | $ | 824,000 | ||||
| Ancillary services | 2,179,627 | 2,052,971 | ||||||
| Energy production | 1,483,887 | 766,353 | ||||||
| Total operating revenues | $ | 6,729,514 | $ | 3,643,324 | ||||
Costs of sales for the years ended December 31, 2007 and 2006 were $1,433,429 and $861,887 yielding gross profits of $5,296,085 and $2,781,437 and gross margins of 79% and 76%, respectively. Our gross margin has been relatively high due to a favorable mix of high margin resource adequacy capacity and ancillary services constituting the largest portion of our revenues. We expect our gross margin to decrease significantly as a percentage of our revenues as we upgrade existing facilities and acquire additional facilities, which are expected to increase our gross energy production.
| | | | | ||||||||||||
| Gross Margin % | ||||||||||||||||
| Years Ended December 31, | 2007 | 2006 | 2007 | 2006 | ||||||||||||
| Cost of sales: | ||||||||||||||||
| Costs of resource adequacy capacity | 245,280 | 47,200 | 92.0 | % | 94.3 | % | ||||||||||
| Costs of ancillary services | 525,443 | 480,681 | 75.9 | % | 76.6 | % | ||||||||||
| Costs of energy production | 662,706 | 334,006 | 55.3 | % | 56.4 | % | ||||||||||
| Total costs of sales | $ | 1,433,429 | $ | 861,887 | 78.7 | % | 76.3 | % | ||||||||
Costs of sales include these major expenses:
| • | Resource Adequacy Capacity — Includes primarily commissions paid to electricity marketers. We expect this revenue stream to remain at a very high margin. |
| • | Ancillary Services — Includes primarily grid management charges, or costs incurred by the ISO directly related to the installation and maintenance of the electrical power grid necessary to permit the provision of energy and ancillary services. These costs are passed through to generators as |
17
| mandated by regulatory and governing bodies. Costs also include variable incentive fees paid to our energy manager for exceeding revenue targets. This is typically a high margin service, although margins have dropped materially during the off-peak periods for non-spin due to the significant drop in market prices noted above. |
| • | Energy Production — Includes variable costs for fuel, primarily natural gas, used in the production of energy as well as pipeline fees for fuel transportation, grid management charges, variable incentive fees, and other direct charges associated with the provision of energy production. We expect energy production gross margins to decrease in future periods upon re-powering Chula Vista and Escondido or acquiring additional facilities. |
Operations and maintenance expenses consist of the direct fixed expenses incurred to operate and maintain our three power generation facilities.
For the years ended December 31, 2007 and 2006 operations and maintenance expenses were $2,438,722 and $1,368,757 respectively, which consisted primarily of fixed charges such as contracted labor, interconnection costs and other period costs associated with MMC Chula Vista, MMC Escondido and MMC Mid-Sun.
Re-commissioning expenses consist of the non-recurring initial planned repairs and re-commissioning costs required to restore electricity generating facilities and all related equipment to operating condition, including fuel and other costs relating to initial test runs of facilities.
For the years ended December 31, 2007 and 2006, re-commissioning costs were $413,904 and $2,615,811, respectively. The 2007 re-commissioning costs related to completing the re-commissioning of MMC Mid-Sun, which we purchased at a total cost of $4,400,000. Re-commissioning costs of $2,615,811 incurred during the year ended December 31, 2006 included $2,155,796 for the re-commissioning of MMC Chula Vista and MMC Escondido that commenced operations on June 12, 2006, and $460,015 for the commencement of re-commissioning of MMC Mid-Sun.
For the year ended December 31, 2007 and 2006, general and administrative expenses were approximately $6,255,377, and $4,585,843 which included non-recurring severance related charges of approximately $1,860,000 in connection with the departure of two of our former officers. The balance of general and administrative expenses for 2007 was primarily attributable to compensation and professional fees. General and administrative expenses in 2006 were driven primarily by merger transaction related costs of approximately $1,748,000, and compensation and professional fees, which generally did not commence until after our merger on May 15, 2006.
While general and administrative expenses are currently a large percentage of our overall expenses, we expect that the percentage will be reduced as we continue to implement our growth strategy.
Interest income for the years ended December 31, 2007 and 2006 were $994,297 and $24,428. Interest income from 2007 reflects investment of the proceeds of the recently completed public offering in high-yield investment grade money market funds and debt securities partially offset by senior debt interest expense. We expect to continue to earn net interest income until the proceeds from the offering are utilized to acquire additional assets, which we expect to include debt financing, which will result in a material increase in interest expenses.
Other expenses, net for the years ended December 31, 2007 and 2006 were income of $135,995 and a net expense of $192,627. Other income in 2007 reflects a recovery of legal and professional fees incurred prior periods primarily relating to the unsuccessful financing activities prior to pursuing the recently completed public offering. Other expenses in 2006 primarily reflect financing costs recognized in connection to the reverse merger as well as a registration penalty of approximately $136,000 paid to shareholders discussed in Footnote 10 of our consolidated financial statements included in Item 8 of this Annual Report.
18
On July 5, 2007, we consummated a public offering of 9,090,910 shares of our common stock at $5.50 per share pursuant to a registration statement. This transaction resulted in net proceeds to us of approximately $46.1 million. As of December 31, 2007, we had $42.6 million in cash and equivalents as well as $4.1 million in securities available for sale which can be liquidated as required to fund our operations.
We believe that our existing cash resources will be sufficient to satisfy our cash requirements for at least the next twelve months. However, our existing cash resources may not be sufficient to fully fund our acquisition growth strategy. Such acquisitions may require us to obtain additional debt financing or other funding in a short period of time. The extent and timing of the capital requirements will be contingent on the specific acquisition targets we are able to source. If we fail to obtain sufficient capital resources on terms acceptable to us, it would have a material adverse effect on our plans to make additional acquisitions, cover unplanned repairs, required capital expenditures and/or our current business, results of operations, liquidity and financial condition. If we issue additional equity and/or debt securities to meet our future capital requirements, the terms of any future equity financings may be dilutive to our stockholders and the terms of any debt financings may contain restrictive covenants that may also negatively affect our stockholders. Our ability to effect future financings will depend on the status of our business prospects as well as conditions prevailing in the capital markets.
On January 31, 2006, MMC North America, one of our wholly owned subsidiaries entered into a Loan and Security Agreement with TD Banknorth providing for a $3.5 million senior debt facility including a $3.0 million term loan and a $500,000 revolving loan. The term loan provides for interest-only payments during the first twelve months, and 81 equal principal payments in the amount of $37,038 thereafter, with a final maturity date of May 3, 2013. The term loan bears interest at a fixed rate equal to 7.58%.
Advances against the revolver are payable on demand and bear interest at the prime rate plus 1.00%. Beginning in 2007, amounts outstanding under the revolver must be repaid in full and a zero balance maintained for at least 30 consecutive days at any time during the year. We have not borrowed under the revolver.
The loan agreement places certain restrictions on MMC North America's ability to upstream cash to our parent, MMC Energy, Inc., as well as restrictions on transactions with affiliates. The loan agreement further subjects MMC North America to certain financial and other covenants, including maintaining a minimum net worth and minimum debt service coverage ratio, as such terms are defined in the loan agreement. These covenants are tested on an annual basis. For the years ended December 31, 2007 and 2006, MMC North America was not in violation of any such covenants. The loans were personally guaranteed, jointly and severally, by certain current and former officers of our company, and any losses sustained by any officer were subject to indemnification by us. On August 30, 2007 the officers who remained subject to the guaranty were released from the guaranties by the bank.
MMC North America has arranged for the issuance by TD Banknorth of an irrevocable letter of credit in the amount of $100,000 to counterparty under an energy services agreement entered into during November 2006. The counterparty may draw upon the letter of credit to recover liquidated damages suffered by the counterparty in connection with any energy sales it may make on behalf of MMC North America in the event MMC North America fails to meet its obligations, or for any other unsatisfied obligations under the energy services agreement. The letter of credit expires on February 28, 2009. Availability under the revolver is reduced from $500,000 to $400,000 while the letter of credit remains outstanding
We do not have any off-balance sheet arrangements that are reasonably likely to have a current or future effect on our financial condition, revenues, results of operations, liquidity or capital expenditures, nor do we participate in non-exchange traded contracts requiring fair value accounting treatment.
In connection with the planned Chula Vista an Escondido upgrades and possible future acquisition of “mid-merit” electricity generation facilities, which are neither true baseload nor true peaking facilities, but somewhere in between, we may engage in certain hedging transactions. Such facilities would be more expensive to purchase but would be expected to generate substantially more energy production revenues. For such assets, hedging the commodity price risk becomes more critical. We expect to enter into intermediate term
19
financially settled hedge contracts that would serve the purpose of shifting the price risk of fuel cost and electricity pricing onto the counterparty, in effect swapping commodity price risk for credit risk. Management's experience in this area will become more critical with the purchase of such assets.
Our business is seasonal, with a relatively high proportion of revenues and operating cash flows generated during the third quarter of the fiscal year, which includes the peak summer months for energy demand. As we derive most of our revenues from selling energy and ancillary services at then-current spot market prices, as opposed to under longer term fixed-price contracts, our revenues and operating income are highly exposed to the seasonal fluctuations in natural gas and electricity, which corresponds to peak summer demand. The effect of inflation on our revenue and operating results was not significant.
See Note 2 of the Notes to Condensed Consolidated Financial Statements included in Item 8 of this Annual Report for recent accounting pronouncements.
Not Applicable.
20
F-1
Board of Directors
MMC Energy, Inc.
New York, New York
We have audited the accompanying consolidated balance sheet of MMC Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the two years in the period ended December 31, 2007. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on the financial statements based upon our audits.
We have conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of MMC Energy, Inc. at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
/s/ RBSM LLPRBSM LLP
New York, New York
March 11, 2008
F-2
| | | ||||||
| December 31, 2007 | December 31, 2006 | |||||||
| ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and equivalents | $ | 42,582,697 | $ | 4,923,063 | ||||
| Accounts receivable (Note 3) | 62,855 | — | ||||||
| Unbilled receivables (Note 3) | — | 157,131 | ||||||
| Spare parts inventories | 94,089 | — | ||||||
| Prepaids (Note 3) | 215,254 | 261,901 | ||||||
| Securities avaliable for sale (Note 4) | 4,075,000 | — | ||||||
| Total current assets | 47,029,895 | 5,342,095 | ||||||
| Property, plant and equipment, net (Note 5) | 6,721,153 | 7,355,576 | ||||||
| Other assets: | ||||||||
| Deferred acquisition costs (Note 6) | 2,488,756 | 749,760 | ||||||
| Long-term deposits | 98,630 | 75,000 | ||||||
| Other assets and deferred charges (Note 7) | 390,762 | — | ||||||
| Total other assets | 2,978,148 | 824,760 | ||||||
| Total assets | $ | 56,729,196 | $ | 13,522,431 | ||||
| LIABILITIES & STOCKHOLDERS' EQUITY | ||||||||
| Current Liabilities: | ||||||||
| Current maturities of long-term debt (Note 8) | $ | 444,456 | $ | 444,456 | ||||
| Accounts payable | 453,654 | 540,992 | ||||||
| Deferred revenue | 65,713 | 212,290 | ||||||
| Other accrued expenses | 769,164 | 856,166 | ||||||
| Accrued compensation | 1,740,077 | 435,476 | ||||||
| Total current liabilities | 3,473,064 | 2,489,380 | ||||||
| Long-term debt (Note 8) | 1,962,936 | 2,407,392 | ||||||
| Commitments & contingencies (Note 9) | ||||||||
| Stockholders' Equity (Note 11) | ||||||||
| Preferred Stock; 10,000,000 shares authorized; none issued and outstanding; $.001 par value | — | — | ||||||
| Common stock; 300,000,000 shares authorized with 13,917,347 issued and outstanding as of December 31, 2007 and 4,768,876 outstanding as of December 31, 2006; $.001 par value | 13,917 | 4,769 | ||||||
| Additional paid-in capital | 61,658,887 | 15,227,586 | ||||||
| Accumulated deficit | (10,379,608 | ) | (6,606,696 | ) | ||||
| Total stockholders' equity | 51,293,196 | 8,625,659 | ||||||
| Total liabilities and stockholders' equity | $ | 56,729,196 | $ | 13,522,431 | ||||
The accompanying footnotes are an integral part of these consolidated financial statements
F-3
| | | ||||||
| Year Ended December 31, 2007 | Year Ended December 31, 2006 | |||||||
| Operating revenues: | ||||||||
| Resource adequacy capacity | $ | 3,066,000 | $ | 824,000 | ||||
| Ancillary services | 2,179,627 | 2,052,971 | ||||||
| Energy production | 1,483,887 | 766,353 | ||||||
| Total operating revenues | 6,729,514 | 3,643,324 | ||||||
| Costs of sales: | ||||||||
| Costs of resource adequacy capacity | 245,280 | 47,200 | ||||||
| Costs of ancillary services | 525,443 | 480,681 | ||||||
| Costs of energy production | 662,706 | 334,006 | ||||||
| Total costs of sales | 1,433,429 | 861,887 | ||||||
| Gross Profit | 5,296,085 | 2,781,437 | ||||||
| Operating expenses: | ||||||||
| Depreciation | 1,091,286 | 626,298 | ||||||
| Operations and maintenance | 2,438,722 | 1,368,757 | ||||||
| Re-commissioning expenses | 413,904 | 2,615,811 | ||||||
| General and administrative expenses | 6,255,377 | 4,585,843 | ||||||
| Total operating expenses | 10,199,289 | 9,196,709 | ||||||
| Loss from operations | (4,903,204 | ) | (6,415,272 | ) | ||||
| Interest and other expenses | ||||||||
| Interest expense | 226,915 | 224,272 | ||||||
| Interest income | 1,221,212 | 248,700 | ||||||
| Interest income (expense), net | 994,297 | 24,428 | ||||||
| Other (income) expense, net | (135,995 | ) | 192,627 | |||||
| Total interest and other (income) expenses | (1,130,292 | ) | 168,199 | |||||
| Net loss before provision for income taxes | (3,772,912 | ) | (6,583,471 | ) | ||||
| Provision for income taxes | — | — | ||||||
| Net loss | $ | (3,772,912 | ) | $ | (6,583,471 | ) | ||
| Basic loss per common share | ||||||||
| Net loss per share | $ | (0.41 | ) | $ | (1.53 | ) | ||
| Weighted average shares outstanding | 9,273,007 | 4,296,465 | ||||||
| Diluted loss per common share | ||||||||
| Net loss per share | $ | (0.41 | ) | $ | (1.53 | ) | ||
| Weighted average shares outstanding | 9,273,007 | 4,296,465 | ||||||
| Weighted average shares outstanding – basic | 9,273,007 | 4,296,465 | ||||||
| Dilutive effect of assumed exercise of employee stock options, warrants and immediate vesting of unvested stock awards | — | — | ||||||
| Weighted average shares outstanding – diluted | 9,273,007 | 4,296,465 | ||||||
| Anti-dilutive shares excluded from diluted EPS | 289,893 | 66,549 | ||||||
The accompanying footnotes are an integral part of these consolidated financial statements
F-4
| | | | | | |||||||||||||||
| Common Shares $.001 Par Value | Common Stock Amount | Additional Paid-in Capital | Accumulated Deficit | Total Stockholders' Equity | ||||||||||||||||
| Balance at December 31, 2005 | $ | — | $ | — | $ | (23,225 | ) | $ | 186,747 | |||||||||||
| Capital subscribed | — | — | — | — | 3,008,333 | |||||||||||||||
| Cash contributions, net | — | — | — | — | 165,028 | |||||||||||||||
| High Tide Shares retained by High Tide stockholders in connection with merger with MMC North America on May 15, 2006 | 1,175,000 | 1,175 | 10,575 | — | 11,750 | |||||||||||||||
| Shares issued to MMC North America members in connection to merger with High Tide on May 15, 2006 | 2,387,500 | 2,388 | 3,380,945 | — | — | |||||||||||||||
| Stock awards and options | 6,279 | 6 | 199,369 | — | 199,375 | |||||||||||||||
| Common shares issued for cash | 1,200,097 | 1,200 | 11,636,697 | — | 11,637,897 | |||||||||||||||
| Net loss | — | — | — | (6,583,471 | ) | (6,583,471 | ) | |||||||||||||
| Balance at December 31, 2006 | 4,768,876 | $ | 4,769 | $ | 15,227,586 | $ | (6,606,696 | ) | $ | 8,625,659 | ||||||||||
| Stock awards and options, net of cancellations | 12,561 | 13 | 378,998 | — | 379,011 | |||||||||||||||
| Common shares issued for cash | 9,135,910 | 9,135 | 46,052,303 | — | 46,061,438 | |||||||||||||||
| Net loss | — | — | — | (3,772,912 | ) | (3,772,912 | ) | |||||||||||||
| Balance at December 31, 2007 | 13,917,347 | $ | 13,917 | $ | 61,658,887 | $ | (10,379,608 | ) | $ | 51,293,196 | ||||||||||
The accompanying footnotes are an integral part of these consolidated financial statements
F-5
| | | ||||||
| Year Ended December 31, 2007 | Year Ended December 31, 2006 | |||||||
| Operating Activities of Continuing Operations | ||||||||
| Net loss | $ | (3,772,912 | ) | $ | (6,583,471 | ) | ||
| Adjustments to reconcile net loss to cash used in operating activities | ||||||||
| Depreciation | 1,091,286 | 626,298 | ||||||
| Stock-based compensation | 379,011 | 199,375 | ||||||
| Acquisition costs | 11,750 | |||||||
| Changes in current assets & liabilities | ||||||||
| Decrease (Increase) in receivables | 94,276 | (157,131 | ) | |||||
| (Increase) in spare parts inventories | (94,089 | ) | — | |||||
| Decrease (Increase) in prepaids | 46,647 | (61,901 | ) | |||||
| (Decrease) Increase in accounts payable | (87,338 | ) | 441,315 | |||||
| (Decrease) Increase in deferred revenues | (146,577 | ) | 212,290 | |||||
| (Decrease) Increase in other accrued expenses | (87,002 | ) | 844,166 | |||||
| Increase in accrued compensation | 1,178,068 | 435,476 | ||||||
| Other non-current, net | (414,393 | ) | (75,000 | ) | ||||
| Net cash used in operations | (1,813,023 | ) | (4,106,833 | ) | ||||
| Investing Activities of Continuing Operations | ||||||||
| Purchases of property, plant and equipment | (347,564 | ) | (7,979,986 | ) | ||||
| Purchases of securities available for sale, net | (4,075,000 | ) | — | |||||
| Deferred acquisition costs | (1,721,762 | ) | (653,901 | ) | ||||
| Net cash used in investing activities | (6,144,326 | ) | (8,633,887 | ) | ||||
| Financing Activities of Continuing Operations | ||||||||
| Proceeds from issuance of long-term debt | — | 3,000,000 | ||||||
| Repayment of long-term debt | (444,456 | ) | (148,152 | ) | ||||
| Member interest issued, net | — | 165,028 | ||||||
| Proceeds from issuance of stock, net | 46,061,439 | 11,637,897 | ||||||
| Net cash provided by financing activities | 45,616,983 | 14,654,773 | ||||||
| Net increase in cash and cash equivalents | 37,659,634 | 1,914,053 | ||||||
| Beginning cash and cash equivalents at beginning of period | 4,923,063 | 3,009,010 | ||||||
| Cash and cash equivalents at end of period | $ | 42,582,697 | $ | 4,923,063 | ||||
| Supplemental disclosures: | ||||||||
| Cash paid for taxes | $ | — | $ | — | ||||
| Cash paid for interest | 156,139 | 203,284 | ||||||
| Non-cash investing and financing activities | ||||||||
| Subscription agreements for member interests that were subscribed and paid in 2005 but not accepted by the company until January 3, 2006 | $ | — | $ | 3,008,333 | ||||
| Stock-based compensation | 379,011 | 199,375 | ||||||
| Acquisition costs in reverse merger with High Tide Ventures, Inc. | — | 11,750 | ||||||
The accompanying footnotes are an integral part of these consolidated financial statements
F-6
The Company is an energy management company that acquires and actively manages a portfolio of small to mid size, or below 250 megawatt, electricity generating assets. In January 2006 the Company acquired two power generation facilities located in Chula Vista and Escondido, California, and in November 2006, the Company acquired a facility in Bakersfield, California (“Mid-Sun”). The Company is pursuing additional acquisitions of small to medium-sized power generating facilities primarily in California, Texas, the Mid-Atlantic and the Northeastern United States. The Company has also begun the process of upgrading the Chula Vista and Escondido facilities.
MMC Energy, Inc. was originally incorporated in Nevada under the name High Tide Ventures, Inc. on February 13, 2003. On May 3, 2006, High Tide Ventures changed its name to MMC Energy, Inc. On May 15, 2006, a wholly-owned subsidiary of MMC Energy, Inc. merged with and into MMC Energy North America LLC, a Delaware limited liability company. Prior to this merger, MMC North America LLC acquired the power generating facilities located in Chula Vista and Escondido, California and otherwise conducted the Company’s current business as described throughout this Annual Report. Prior to this merger, MMC Energy, Inc. did not conduct meaningful operations. As a result of the merger, MMC Energy, Inc. thus acquired thebusiness of MMC Energy North America LLC, including the electricity generating facilities, and the former members of MMC Energy North America LLC received shares of common stock of MMC Energy, Inc. On September 22, 2006, the Company was reincorporated as a Delaware corporation by means of a merger of the existing Nevada corporation with and into MMC Energy, Inc., a newly-formed Delaware corporation. Pursuant to the reincorporation merger, the Delaware corporation succeeded to the business of the Nevada corporation and the separate existence of the Nevada corporation ceased.
MMC was considered a development stage enterprise until June 12, 2006, comparisons of certain periods in 2006 with corresponding periods in 2007 for our results of operations may not be meaningful. Additionally, due to the commencement of operations in June, our 2006 results do not reflect a full year's run rate for revenues and most expenses.
All significant inter-company transactions and balances have been eliminated in consolidation.
These consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries: MMC Energy North America LLC, MMC Escondido LLC, MMC Chula Vista LLC and MMC Mid-Sun LLC. All intercompany accounts and transactions have been eliminated.
For revenue from products and services, the Company recognizes revenue in accordance with SEC Staff Accounting Bulletin No. 101, “Revenue Recognition in Financial Statements” (“SAB 101”). SAB 101 requires that four basic criteria must be met beforerevenue can be recognized: (1) persuasive evidence of an arrangement exists; (2) delivery has occurred or services have been rendered; (3) the selling price is fixed and determinable; and (4) collectibility is reasonably assured. Determination of criteria (3) and (4) are based on management’s judgments regarding the fixed nature of the selling prices of the products delivered/services rendered and the collectibility of those amounts. Provisions for discounts and rebates to customers, estimated returns and allowances, and other adjustments are provided for in the same period the related sales are recorded. The Company defers any revenue for which the product has not been delivered or services have not been rendered or are subject to refund until such time that the Company and the customer jointly determine that the product has been delivered or services have been rendered or no refund will be required.
F-7
On December 17, 2003, the SEC staff released Staff Accounting Bulletin (SAB) No. 104, Revenue Recognition. The staff updated and revised the existing revenue recognition in Topic 13, Revenue Recognition, to make its interpretive guidance consistent with current accounting guidance, principally EITF Issue No. 00-21, “Revenue Arrangements with Multiple Deliverables.” The Company’s revenue recognition policies are consistent with this guidance; therefore, this guidance will not have an immediate impact on the Company’s financial statements.
The Company records revenues in connection with delivering electricity and ancillary services, generally being on call to provide power on ten minutes notice, to the California Independent System Operator (“CAISO”), or such other first parties as it may contract with directly from time to time. The Company commenced earning revenues during June 2006. In the event that the Company is compensated for services before they are rendered, the Company records deferred revenue in the liability section of its balance sheet.
The Company’s electricity generating facilities are generally referred to as “peaker” plants. Peaker plants are used to balance unexpected short term surges in demand, making them critical to the reliability, or “insurance,” of the power grids they serve. The Company’s revenues to date have been earned by providing resource adequacy capacity, ancillary services and energy production in the State of California.
| • | Resource Adequacy Capacity — Regulatory capacity payments for generators of any type are based strictly on total installed capacity measured in megawatts (“MW”). In the California market where the Company currently operates exclusively, market-based capacity revenues are earned through resource adequacy contracts, whereby the counterparty can point to the Company’s facilities' installed capacity as a source to supply its peak demand plus a mandatory safety margin as dictated by the California Public Utilities Commission (“CPUC”). The contract does not create an obligation to supply electricity to the counterparty, but does obligate the Company to bid its energy into the CAISO markets on a daily basis such that the Company’s capacity is available to the CAISO, if needed, at the Company’s price. The resource adequacy capacity amount cannot exceed the qualified capacity amount for the resource. Qualified capacity is certified by CAISO. For 2006, the MMC Escondido and MMC Chula Vista facilities were certified by CAISO and the CPUC for 40 MW each, and for 2007, 35.5 MW each and MMC Mid-Sun for 22 MW. |
| • | Ancillary Services — Although there are several types of ancillary services, the Company primarily provides “spin” and “non-spin” services which call for the facilities to be delivering the awarded capacity within 10 minutes of dispatch whether already synchronized to the grid (spin) or not (non-spin). Spin services typically offer higher rates. As of October 9, 2007, Bear Energy L.P. (“Bear”) the Company’s scheduling coordinator advised the Company that it would no longer bid the Company’s facilities into the spin services market due to regulatory uncertainty concerning the Company’s spin qualification with CAISO. Please see Footnote 14 “Subsequent Events” below for more information. |
| • | Energy Production — The company provides electricity to a local power grid through day ahead and real time auctions managed by the CAISO, the “merchant market” or through financial settled bilateral agreements with a utility or other direct counterparty. As the Company has no outstanding electricity purchase agreements or other contracted energy production, all of its energy production revenues are earned in the daily merchant market. |
In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109, deferred income taxes are the result of the expected future tax consequences of temporary differences between the financial statement and tax bases of assets and liabilities. Generally, deferred income taxes are classified as current or non-current in accordance with the classification of the related asset or liability. Those items not related to an
F-8
asset or liability are classified as current or non-current depending on the periods in which the temporary differences are expected to reverse. A valuation allowance is provided against deferred income tax assets in circumstances where management believes the recoverability of a portion of the assets is not reasonably assured. Losses incurred will be carried forward as applicable per SFAS 109 and the Internal Revenue Code and potentially may be used to offset taxable net income generated in the future. The Company has no history of generating taxable net income and may not recognize any tax benefit on losses incurred currently.
For purposes of the Statement of Cash Flows, the Company considers all time deposits and highly liquid debt instruments purchased that mature in three months or less to be cash equivalents.
Accounts receivable are composed substantially of trade accounts receivable that arise primarily from the sale of goods or services on account and are stated at historical cost. Management evaluates accounts receivable to estimate the amount of accounts receivable that will not be collected in the future and records a provision for that amount. The provision for doubtful accounts is recorded as a charge to operating expense, while the credit is recorded in the allowance for doubtful accounts, which reduces accounts receivable. The estimated allowance for doubtful accounts is based primarily on management's evaluation of the aging of the accounts receivable balance, the financial condition of its customers, historical trends, and time outstanding of specific balances. Actual collections of accounts receivable could differ from management's estimates due to changes in future economic, industry or customer financial conditions. Unbilled receivables are for amounts due to the Company for revenues earned in a given period but not yet billed to the customer.
Inventories are stated at cost based on the specific identification method. Inventories consist of spare parts to be used in general operations and maintenance.
Securities Available-for-sale are accounted for under SFAS No. 115 “Accounting for Certain Investments in Debt and Equity Securities.” Securities available for sale are carried at fair value with the unrealized gains or losses, net of tax, included as a component of accumulated other comprehensive income (loss) in stockholders' equity. Realized gains and losses and declines in value judged to be other-than-temporary on available-for-sale securities are included in other income, net. The fair values for marketable debt and equity securities are based on quoted market prices.
Property and equipment are stated at cost. Depreciation is computed principally by the straight-line method at rates based on estimated useful lives as follows:
| | |||
| Office equipment | 3 years | |||
| Machinery, automobiles and equipment | 3 – 10 years | |||
| Software | 3 years | |||
In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,'' long-lived assets are reviewed for impairment annually and whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If an indicator of impairment exists for any grouping of assets, an estimate of undiscounted future cash flows is produced and compared to its carrying value. If an asset is determined to be impaired, the loss is measured by the excess of the carrying amount of the asset over its fair value as determined by an estimate of discounted future cash flows.
F-9
Financial instruments and related items, which potentially subject the Company to concentrations of credit risk, consist primarily of cash and cash equivalents and accounts receivable. The Company places its cash and temporary cash investments with high credit quality institutions. At times, such investments may be in excess of the FDIC insurance limit for each institution.
Concentration of credit risk with respect to accounts receivable is high due to the relatively small number of entities comprising the Company's customer base. For the year December 31, 2007 the Company received 55% of its revenues from one customer, CAISO and received the balance of its revenues from Oxy, Inc. As rated by Moody's, Oxy, Inc. has an issuer credit rating of A3.
The Company’s business is seasonal, with a relatively high proportion of revenues and operating cash flows generated during the third quarter of the fiscal year, which include the peak summer months for energy demand, and a relatively low proportion of revenues and operating cash flows generated during the first quarter. As the Company derives most of its revenues from selling energy and ancillary services at spot market prices, as opposed to under longer term fixed-price contracts, its revenues and operating income are highly exposed to the seasonal fluctuation in commodity pricing, which generally corresponds to peak electricity demand.
All of the Company’s facilities are located in Southern California, and generally provide electricity only in that state. The facilities maintain exempt wholesale generator (“EWG”) status and market based rate (“MBR”) authority as approved by the Federal Energy Regulatory Commission. Accordingly, the Company’s operations are regulated by the local Air Permit Control Boards, the CAISO and other related state and local agencies, as well as the Federal Energy Regulatory Commission. These organizations establish certain rules and limitations on operations and require that the Company maintain in good standing several required licenses and permits, such as permits for air emissions. These organizations may from time to time change the rules under which the Company operates and derives its revenues. The Company believes it has all such required licenses and permits to conduct its operations.
SFAS No. 130 (“SFAS 130”), “Reporting Comprehensive Income,” establishes standards for reporting and displaying of comprehensive income, its components and accumulated balances. Comprehensive income is defined to include all changes in equity except those resulting from investments by owners and distributions to owners. Among other disclosures, SFAS 130 requires that all items that are required to be recognized under current accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. The Company does not have any items of comprehensive income in the period presented.
The Company adopted SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (“SFAS 131”). SFAS 131 establishes standards for reporting information regarding operating segments in annual financial statements and requires selected information for those segments to be presented in interim financial reports issued to stockholders. SFAS 131 also establishes standards for related disclosures about products and services and geographic areas. Operating segments are identified as components of an enterprise about which separate discrete financial information is available for evaluation by the chief operating decision maker, or decision making group, in making decisions concerning how to allocate resources and
F-10
assess performance. The information disclosed herein materially represents all of the financial information related to the Company's principal operating segment.
In the normal course of preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management include the collectibility of accounts receivable, the useful life of long-lived assets, estimates of stock-based compensation and the valuation allowance of deferred tax assets. Actual results could differ from those estimates.
Basic and diluted income or loss per common share is based upon the weighted average number of common shares outstanding during the fiscal year under the provisions of SFAS No. 128, “Earnings Per Share,” and as amended/superseded in SFAS No. 123(R), “Share-Based Payments”(“SFAS 123R”). As the Company incurred a net loss for the years ended December 31, 2007 and 2006, dilutive shares presented for that period are the same as basic shares outstanding. Below is a reconciliation of basic to diluted shares outstanding for the applicable periods:
| | | ||||||
| Basic, Diluted and Anti-dilutive Shares | Year Ended December 31, 2007 | Year Ended December 31, 2006 | ||||||
| Weighted average shares outstanding – basic | 9,273,007 | 4,296,465 | ||||||
| Dilutive effect of assumed exercise of employee stock options, warrants and immediate vesting of unvested stock awards | — | — | ||||||
| Weighted average shares outstanding – diluted | 9,273,007 | 4,296,465 | ||||||
| Anti-dilutive shares excluded from diluted EPS computations | 289,893 | 66,549 | ||||||
Upon consummation of the merger described in Note 13 below, the Company adopted SFAS 123(R) which no longer permits the use of the intrinsic value method under Accounting Principles Board Opinion (“APB”) No. 25 “Accounting for Stock Issued to Employees.” The Company used the modified prospective method allowed by SFAS 123(R), which requires compensation expense to be recorded for all stock-based compensation granted on or after January 1, 2006, as well the unvested portion of previously granted options. The Company is recording the compensation expense on a straight-line basis, generally over the explicit service period of three years (except for retirement eligible employees and retirees). The Company made no stock-based compensation grants before January 1, 2006, and, therefore has no unrecognized stock compensation related liabilities or expense unvested or vested prior to 2006.
F-11
The following tables illustrates the effect that adoption of SFAS No. 123(R) had on the Company’s year ending December 31, 2007 results and cash flows as well as the parameters used in the valuation of options granted in 2007.
| | | | |||||||||||||
| Under Pre-SFAS 123(R) Accounting | SFAS 123(R) Impact | Year Ended December 31, 2007 | ||||||||||||||
| Losses before taxes | $ | (3,509,682 | ) | $ | (263,230 | ) | $ | (3,772,912 | ) | |||||||
| Net loss | (3,509,682 | ) | (263,230 | ) | (3,772,912 | ) | ||||||||||
| Net Loss | ||||||||||||||||
| Basic EPS | $ | (0.38 | ) | $ | (0.03 | ) | $ | (0.41 | ) | |||||||
| Diluted EPS | (0.38 | ) | (0.03 | ) | (0.41 | ) | ||||||||||
| Cash Flows | ||||||||||||||||
| Operating activities | $ | (1,813,023 | ) | $ | — | $ | (1,813,023 | ) | ||||||||
| Financing activities | 45,616,983 | — | 45,616,983 | |||||||||||||
The following table summarizes common stock options outstanding and the related exercise prices under the Company’s 2006 Equity Incentive Plan.
| | | | | | | ||||||||||||||||||
| Options Outstanding | Options Exercisable | |||||||||||||||||||||||
| Grant Year | Exercise Prices | Number Outstanding | Weighted Average Remaining Contractual Life (Years) | Weighted Average Exercise Price | Number Exercisable | Weighted Average Exercise Price | ||||||||||||||||||
| 2006 | $ | 10.00 | 72,000 | 8.37 | $ | 10.00 | 57,334 | $ | 10.00 | |||||||||||||||
| 2007 | $ | 6.50 | 21,000 | 9.33 | $ | 6.50 | — | $ | 6.50 | |||||||||||||||
| Totals | 93,000 | 8.59 | $ | 9.21 | 57,334 | $ | 10.00 | |||||||||||||||||
Transactions during 2007 involving stock options issued to employees are summarized as follows:
| | | ||||||
| Number of Shares | Weighted Average Price Per Share | |||||||
| Outstanding at December 31, 2006 | 107,000 | $ | 10.00 | |||||
| Granted | 21,000 | 6.50 | ||||||
| Exercised | — | — | ||||||
| Cancelled or expired | (35,000 | ) | 10.00 | |||||
| Outstanding at December 31, 2007 | 93,000 | $ | 9.21 | |||||
Based on the Company’s closing stock price of $3.50 at December 31, 2007, stock options currently outstanding had no aggregate intrinsic value, and there were no in-the-money options exercisable. As of December 31, 2007, such options had a weighted-average remaining contractual life of 8.59 years and weighted-average exercise price of $10.00 per share.
F-12
The weighted-average fair value of stock options granted to employees during the year ended December 31, 2007 and the weighted-average significant assumptions used to determine those fair values, using a Black-Scholes option pricing model were as follows:
| | |||
| 2007 | ||||
| Grants Through December 31, 2007 | Stock Option Grants | |||
| Risk-free interest rate | 4.98 | % | ||
| Dividend yield | 0.00 | % | ||
| Expected life | 6 | |||
| Volatility | 108 | % | ||
| Weighted average option grant price | 6.50 | |||
| Weighted average fair value of options granted | $ | 5.46 | ||
In accordance with SFAS 123(R), the company uses the simplified expected term midpoint method to estimate the expected life of its option grants.
The Company accounts for freestanding derivative financial instruments potentially settled in its own common stock under Emerging Issues Task Force (“EITF”) Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company's Own Stock.” Pursuant to EITF Issue No. 00-19, the Company is required to recognize the initial fair value of the applicable contracts (consisting primarily of non-employee stock warrants and options to purchase common stock) as an asset or liability, and subsequently measure the change in the fair value (based on a Black-Scholes computation), with gains and losses included in a statement of operations. No such instruments were issued for the years ended December 31, 2007 and 2006.
The carrying amounts of the Company's cash, trade payables, accrued expenses, and notes payable approximate their estimated fair value due to the short-term nature of those financial instruments. In June 2006, the Company issued warrants to purchase 45,000 shares of common stock at an exercise price of $0.10 per share. These warrants were issued in lieu of cash as payment for professional services rendered to the Company. The warrants were valued at the fair value of the professional services received as determined by usual and customary fees associated with such services in transactions between unrelated parties.
SFAS No.160. In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 requires that a non-controlling interest in a subsidiary be reported as equity and the amount of consolidated net income specifically attributable to the non-controlling interest be identified in the consolidated financial statements. It also requires consistency in the manner of reporting changes in the parent’s ownership interest and requires fair value measurement of any non-controlling equity investment retained in a deconsolidation. The Company will apply the provisions of this statement prospectively, as required, beginning on January 1, 2009 and does not expect the adoption of SFAS 160 to have a material effect on its consolidated financial statements.
SFAS 141(R). In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (“SFAS 141(R)”). SFAS 141(R) retains the fundamental requirements in Statement 141 that the acquisition method of accounting (which Statement 141 called the purchase method) be used for all business
F-13
combinations and for an acquirer to be identified for each business combination. In general, the statement 1) broadens the guidance of SFAS 141, extending its applicability to all events where one entity obtains control over one or more other businesses, 2) broadens the use of fair value measurements used to recognize the assets acquired and liabilities assumed, 3) changes the accounting for acquisition related fees and restructuring costs incurred in connection with an acquisition and 4) increases required disclosures. The Company will apply the provisions of this statement prospectively to business combinations for which the acquisition date is on or after January 1, 2009 and is currently assessing the impact of adoption of SFAS 141(R) on its consolidated financial statements.
SFAS No. 159. In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS 159 permits entities to choose to measure many financial instruments, and certain other items, at fair value. SFAS 159 applies to reporting periods beginning after November 15, 2007. The adoption of SFAS 159 is not expected to have a material impact on the Company’s financial condition or results of operations.
FSP EITF 00-19-2. In December 2006, the FASB issued FASB Staff Position (“FSP”) EITF 00-19-2, “Accounting for Registration Payment Arrangements” (“FSP 00-19-2”) which addresses accounting for registration payment arrangements. FSP 00-19-2 specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB Statement No. 5, Accounting for Contingencies. FSP 00-19-2 further clarifies that a financial instrument subject to a registration payment arrangement should be accounted for in accordance with other applicable generally accepted accounting principles without regard to the contingent obligation to transfer consideration pursuant to the registration payment arrangement. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of EITF 00-19-2, this guidance shall be effective for financial statements issued for fiscal years beginning after December 15, 2006 and interim periods within those fiscal years. The Company does not expect adoption of this FSP will have a material impact on its financial position, operations or cash flows.
SFAS No. 158. In September 2006 the FASB issued its SFAS No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”(“SFAS 158”). This Statement improves financial reporting by requiring an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity or changes in unrestricted net assets of a not-for-profit organization. This Statement also improves financial reporting by requiring an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. At this time the company has no defined benefit postretirement plan in place. The effective date of adoption for an employer with publicly traded equity securities is as of the end of the fiscal year ending after December 15, 2006. The Company does not expect that the adoption of this standard will have a material impact on its financial position, operations or cash flows.
SFAS No. 157. In September 2006 the Financial Account Standards Board (the “FASB”) issued its Statement of Financial Accounting Standards 157, “Fair Value Measurements” (“SFAS 157”). This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, the Board having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this Statement does not require any new fair value measurements. However, for some entities, the
F-14
application of this Statement will change current practice. SFAS 157’s effective date is for fiscal years beginning after November 15, 2007. The Company does not expect that adoption of this standard will have a material impact on its financial position, operations or cash flows.
FSP No AUG AIR-1. In September 2006 the FASB issued FSP No. AUG AIR-1 “Accounting for Planned Major Maintenance Activities” regarding routine maintenance and Planned Major Maintenance Activities (“PMMA”), which effectively disallowed the advance-in-accrual method that had been the industry standard but has been disallowed effective the first fiscal year beginning after December 15, 2006 for all companies. In accordance with the early adoption provisions of this standard the Company has chosen to adopt this standard early, in particular adopting the deferral method for planned major maintenance items. The Company incurred $434,178 of planned major maintenance expenditures in 2007. Minor routine maintenance and unplanned repairs are expensed as incurred.
Certain reclassifications have been made to conform prior period data to the current presentation. These reclassifications had no effect on reported losses.
At December 31, 2007 and 2006 accounts receivable and prepaid items consisted of the following:
| | | ||||||
| December 31, 2007 | December 31, 2006 | |||||||
| Accounts receivable | $ | 62,855 | $ | — | ||||
| Allowance for doubtful accounts | — | — | ||||||
| Total | $ | 62,855 | $ | — | ||||
| Unbilled receivables | $ | — | $ | 157,131 | ||||
| Total | $ | — | $ | 157,131 | ||||
| Prepaid insurance | $ | 114,784 | $ | 51,046 | ||||
| Prepaid expenses | 100,470 | 93,710 | ||||||
| Short-term deposits | — | 117,145 | ||||||
| Total | $ | 215,254 | $ | 261,901 | ||||
Securities Available-for-sale are accounted for under SFAS No. 115 “Accounting for Certain Investments in Debt and Equity Securities.” Securities available for sale are carried at fair value with the unrealized gains or losses, net of tax, included as a component of accumulated other comprehensive income (loss) in stockholders' equity. Realized gains and losses and declines in value judged to be other-than-temporary on available-for-sale securities are included in other income, net. The fair values for marketable debt and equity securities are based on quoted market prices. At the report date securities available for sale consisted of municipal variable-rate demand notes (“VRDNs”). VRDNs are long-term bonds that have an embedded put option. This put is at par (100) and is 7 days from the point of exercise. Thus, rolling liquidity is available on this position on trade date plus seven days basis. In addition due to the presence of the put the VRDNs are generally never subject to a change in market value and thus does not generate any mark-to-market adjustments except in extraordinary market situations.
F-15
At December 31, 2007 and December 31, 2006 property, plant and equipment consisted of the following:
| | | ||||||
| December 31, 2007 | December 31, 2006 | |||||||
| Land | $ | 375,000 | $ | 375,000 | ||||
| Automobile | 21,927 | 20,427 | ||||||
| Office equipment | 115,825 | 26,918 | ||||||
| Machinery, equipment & other | 7,925,985 | 7,559,529 | ||||||
| 8,438,737 | 7,981,874 | |||||||
| Accumulated depreciation | (1,717,584 | ) | (626,298 | ) | ||||
| Total | $ | 6,721,153 | $ | 7,355,576 | ||||
Depreciation for the years ended December 31, 2007 were $1,091,286 and $626,298, respectively.
Deferred costs in connection with acquisitions and capital raises are accounted for based upon their stage in the acquisition/financing process. Costs of acquisitions and or financings can be broadly classified in four categories: exploratory, pre-acquisition, in-process and in-service. Typically, exploratory costs are expensed as incurred. When a financing or acquisition is determined to be probable as per management’s assessment all costs in connection with such transaction are eligible to be capitalized as well as throughout the actual implementation. When the acquisition is completed, related deferred costs are capitalized as a component of the asset cost basis and depreciated over the useful life of the asset. Deferred costs related to the Company’s recently completed public stock offering were offset against gross proceeds received in July 2007. Outstanding deferred costs consisted of the following:
| | | ||||||
| Deferred Costs | December 31, 2007 | December 31, 2006 | ||||||
| Deferred acquisition costs – Chula Vista | $ | 2,202,176 | $ | 749,760 | ||||
| Deferred acquisition costs – Escondido | 286,580 | — | ||||||
| Total | $ | 2,488,756 | $ | 749,760 | ||||
Other assts and deferred charges consist of $390,762 of deferred maintenance charges in connection with Planned Major Maintenance Activities (“PMMA”) for large assets as of December 31, 2007 net of amortization. The cost of these PMMA are capitalized and then recognized over the earlier of the (i) remaining life of the asset or (ii) until the next PMMA for that equipment. Amortization of deferred maintenance charges in connection with PMMA were $43,416 and $0 for the years ended December 31, 2007 and 2006, respectively.
On January 31, 2006, MMC North America entered into a Loan and Security Agreement (the “Loan Agreement”) with TD Banknorth (the “Bank”), for a $3.5 million senior debt facility, including a $3.0 million term loan (the “Term Loan”) and a $500,000 revolving loan (the “Revolver,” together with the Term Loan, the “Loans”). The Term Loan provides for interest payments only for the first nine months, and 81 monthly principal payments in the amount of $37,038 each thereafter, with a final maturity date of May 3, 2013. The Term Loan bears interest at a fixed rate equal to 7.58%. Approximately $2.1 million of the Term Loan proceeds were funded into an escrow account under control of the Bank and restricted in use to valid repair and re-commissioning costs in accordance with a re-commissioning plan agreed to between MMC North America and the Bank. The remaining proceeds, net of related transaction costs, were used for general working capital purposes. All escrowed funds for repair and re-commissioning were expended for the intended use.
F-16
Advances against the Revolver are payable on demand and bear interest at the Prime Rate plus 1.00%. Beginning in 2007, amounts outstanding under the Revolver must be repaid in full and a zero balance maintained for at least 30 consecutive days at any time during the year. MMC North America has not made any borrowings under the Revolver.
The Loan Agreement places certain restrictions on MMC North America’s ability to make distributions to the Company and on transactions with affiliates. The Loan Agreement further subjects MMC North America to certain financial and other covenants, including maintaining a minimum Net Worth and minimum Debt Service Coverage ratio. The financial covenants are measured annually. During the last measurement of these covenants, for the twelve months ended December 31, 2007, the company was in compliance with all covenants. The loans are collateralized by substantially all assets of MMC North America. The loans were personally guaranteed, jointly and severally, by the two principal officers of the Company, and any losses sustained by any officer were subject to indemnification by the Company. On August 30, 2007 the two officers were released from the guaranties by the Bank.
In February 2007, the Company announced that it had learned that one hundred thousand shares of its common stock issued as part of a 1.2 million share private placement transaction it consummated in May 2006 were purchased by an entity controlled by Louis Zehil, who at the time of the purchase was a partner of the Company’s external legal counsel for the private placement transaction, McGuireWoods LLP. The Company also announced that it believes that Mr. Zehil improperly caused the Company’s former transfer agent not to place a required restrictive legend on the certificate for these one million shares and that Mr. Zehil then caused the entity he controlled to resell these shares. The Company reported Mr. Zehil’s conduct to the Securities and Exchange Commission (the “SEC”) and, subsequently, the SEC recently sued Mr. Zehil in connection with this matter further alleging that Mr. Zehil engaged in a similar fraudulent scheme with respect to six additional public companies represented at the relevant time by McGuireWoods LLP.
Persons who purchased shares directly from Mr. Zehil when he resold his shares may have a rescission right versus Mr. Zehil, and could make the claim that this rescission right somehow extends to the Company as well. One or more of the Company’s investors from the Company’s May 2006 private placement of 1.2 million shares could also claim a rescission right. It is also possible that one or more of the Company’s stockholders could claim that they somehow suffered a loss as a result of Mr. Zehil’s conduct and attempt to hold the Company responsible for their losses. The Company is unable to predict the extent of its ultimate liability with respect to any and all future securities matters. If any such claims are successfully made against the Company and it is not adequately indemnified for those claims from available sources of indemnification, then such claims could have a material adverse effect on the Company’s financial condition and operating results. The Company also may incur significant costs resulting from its investigation of this matter, any litigation it may initiate as a result and the Company’s cooperation with governmental authorities. The Company may not be adequately indemnified for such costs from available sources of indemnification.
MMC North America has arranged for the issuance by the Bank of an irrevocable letter of credit in the amount of $100,000 (the “Letter of Credit”) to a counterparty under an energy services agreement entered into in November 2006 (the “ESA”). The counterparty may draw upon the Letter of Credit to recover liquidated damages suffered by the counterparty in connection with any energy sales it may make on behalf of MMC North America and MMC Mid-Sun in the event MMC North America or MMC Mid-Sun fails to meet its obligations, or for any other unsatisfied obligations under the ESA. The Letter of Credit expires on February 28, 2009. Availability under the Revolver is reduced from $500,000 to $400,000 while the Letter of Credit remains outstanding.
F-17
As the Company’s facilities are located in California, they are exposed to the risk of potential damage from a catastrophic event such as an earthquake. In addition, the Chula Vista facility lies within a designated flood plane and is therefore potentially at risk if subject to a 100 year flood event. While the Company generally insures its facilities at replacement cost, the Company’s insurance policy imposes a $1 million limit on claims resulting from an earthquake or flood. Supplemental coverage for these risks is cost prohibitive and therefore the Company has foregone purchasing such coverage. Accordingly, should any of the Company’s facilities be damaged by such an event, the insurance proceeds to the Company may not be sufficient to cover the costs required to restore such facilities to operating condition. Furthermore, should such a catastrophic event result in the permanent loss of any of its three facilities, the Company believes the insurance proceeds would not be sufficient to recover the loss of future cash flows, or expected market value, of the facility.
The Company expects to file a complaint with the Federal Energy Regulatory Commission (“FERC”) seeking an order directing the CAISO to allow the Company to participate in the spinning reserve market. The CAISO has informed the Company that it may seek rescission of all spinning reserve revenues paid to date should the Company file the complaint. The company believes it is entitled to retain these revenues and intends to vigorously oppose any such action by the CAISO.
The Company is unable to gauge the extent of its ultimate liability with respect to this and any and all future regulatory matters. The costs and other effects of any future litigation, regulatory proceedings, legal and administrative cases, settlements, judgments, claims and changes in this matter will not have a material adverse effect on the Company’s financial condition and liquidity but may have a material impact on future operating results.
We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates that it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonable estimated. Funds spent to remedy these contingencies are charged against a reserve, if one exists, or charged to current period operations. When a range of probable loss can be estimated, the Company accrues the most likely amount or at least the minimum of the range of probable loss.
The Company’s primary office space is currently leased through December 31, 2010.
A table summarizing long-term commitments for the next four years and thereafter is presented below:
| | | | | | | ||||||||||||||||||
| Total | 2008 | 2009 | 2010 | 2011 | Thereafter | |||||||||||||||||||
| Long-term debt | $ | 2,407,392 | $ | 444,456 | $ | 444,456 | $ | 444,456 | $ | 444,456 | $ | 629,568 | ||||||||||||
| Rental commitments | 1,851,250 | 264,797 | 278,105 | 285,348 | 214,500 | 808,500 | ||||||||||||||||||
| Total Obligations | $ | 4,258,642 | $ | 709,253 | $ | 722,561 | $ | 729,804 | $ | 658,956 | $ | 1,438,068 | ||||||||||||
The Company has consulting agreements with outside contractors to provide various services. The Agreements are generally for a term of 12 months from inception and renewable automatically from year to year unless either the Company or the Consultant terminates such engagement by written notice.
The Company is subject to legal proceedings and claims which arise in the ordinary course of its business. Although occasional adverse decisions or settlements may occur, the Company believes that the final disposition of such matters should not have a material adverse effect on its financial position, results of operations or liquidity. Neither the Company nor any subsidiary has any involvement in any legal proceeding as of the report date.
Neither the Company nor any subsidiary has any involvement in any legal proceeding as of the report date.
F-18
Under the Company’s 2006 Equity Incentive Plan (the “Plan”), 500,000 shares of common stock were reserved for issuance as incentive awards to executive officers, key employees and directors and outside consultants. As of December 31, 2007, 93,000 shares have been granted to employees, net of cancellations, in the form of stock option grants, with a weighted average exercise price of $9.21 per share, consistent with the market value of the Company’s common stock at the time of issuances.
For the year ended December 31, 2007 and 2006 the company issued 12,561 and 0 shares of restricted stock, respectively.
On the closing of the Merger described in Note 13 below (the “Merger”), MMC North America’s outstanding equity interests were surrendered by the holders thereof for 2,387,500 shares of common stock of the Company, par value $0.001 per share (“Common Stock”). The existing stockholders of Pubco (as defined in Note 13 below) retained the 1,175,000 shares of Common Stock outstanding prior to the Merger and concurrently with the Merger, the Company issued 1,000,097 additional shares of Common Stock in a private placement for total proceeds of $10,000,966. On May 26, 2006, the Company issued an additional 200,000 shares of Common Stock under the same terms as the first private placement for additional proceeds of $2,000,000. The Company realized total proceeds of $11,637,897 net of direct financing costs of $813,069, of which $450,000 was settled in the form of warrants to purchase 45,000 shares of Common Stock at an exercise price of $0.10 per share. These warrants were exercised in 2007 resulting in the issuance of 45,000 shares. During the quarter ended December 31, 2007, the Company issued no shares of restricted stock to its employees as compensation. As of the date of this report, the Company had 300,000,000 shares authorized under its Certificate of Incorporation and had issued and outstanding 13,917,347 shares of Common Stock. As of such date, the Company also had 10,000,000 shares of preferred stock authorized under its Certificate of Incorporation, none of which was issued or outstanding.
In connection with the issuance of the 1,200,097 shares of Common Stock in the private placements described above, the Company was obligated to file a registration statement to permit the resale of the shares issued in the private placements with the Securities and Exchange Commission (the “SEC”) by September 12, 2006. If the registration statement was not filed with the SEC by that date or if the SEC did not declare the registration statement effective within 120 days after filing, the Company is subject to liquidated damages payable to the holders of the shares issued in the private placements (the “Holders”) in cash equal to 1% per month of the purchase price of the shares issued, or $120,000 per month, until 12 months after the date of issue. From that point forward, penalties are limited to only those shares that are not otherwise freely tradable under SEC Rule 144, which rule limits the volume of shares that may be resold by each Holder for a period from 12 to 24 months after the date they were issued.
On October 17, 2006, a majority of Holders approved an extension of the filing requirement to December 31, 2006, and agreed to cap aggregate registration penalties at 12%. However, the aforementioned penalties accrued up to October 17, 2006 were not waived. Accordingly, the Company has reserved for such penalties for the period from September 13, 2006 through October 17, 2006, or 34 days, at the rate of 1% per month, amounting to $136,000 charged to non-operating financing costs. These penalties were paid out to the shareholders of record in January 2007. On December 29, 2006, the Company filed a registration statement with the SEC thereby complying with the approved extension. The SEC declared the registration statement effective on April 5, 2007 thereby avoiding any further penalties relating to this registration requirement.
On April 19, 2007, the Company effected a one-for-ten reverse stock split of its outstanding shares of common stock, $0.001 par value. Total authorized shares and par value remain unchanged. All references in the financial statements and notes to financial statements, numbers of shares and share amounts have been retroactively restated to reflect the reverse split, unless explicitly stated otherwise.
F-19
On July 5, 2007, the Company completed a public offering of 9,090,910 shares of its common stock at $5.50 per share pursuant to a Form SB-2 Registration Statement under the Securities Act of 1933.
The Company had no related party transactions for the year ended December 31, 2007.
The Company paid management fees of $260,000, inclusive of a $60,000 transaction fee, capitalized as a component of the acquisition costs of the Facilities, and $200,000 in quarterly management fees expensed as incurred, in the nine months ended September 30, 2006 to MMC Energy Management, LLC, (“MMC Management”), an affiliate controlled by the three executive officers of the Company. Effective July 1, 2006, the management services agreement between MMC North America and MMC Management was terminated, and replaced by a new management services agreement between MMC North America and the Company, such that there will be no future impact on the Company’s consolidated earnings and cash flows from the management fee. As required by the Merger Agreement, no further business has been transacted between the Company and MMC Management subsequent to the Merger.
MMC Management was dissolved on November 8, 2006.
MMC Energy, Inc. was originally incorporated in Nevada under the name High Tide Ventures, Inc. (“Pubco”). On May 3, 2006, Pubco changed its name to MMC Energy, Inc. On May 15, 2006, MMC Energy Acquisition Corp., a wholly-owned subsidiary of Pubco (“Acquisition Sub”), merged (the “Merger”) with and into MMC Energy North America. As described in Note 1 above, prior to the Merger, MMC North America owned the Facilities and conducted the Company’s current business and Pubco did not conduct meaningful operations. Pursuant to the Merger, Pubco thus acquired the business of MMC North America, including the Facilities, and the former members of MMC North America received shares of Pubco common stock. Simultaneously with the Merger, Pubco consummated a $12 million private placement of shares of common stock. This Merger is accounted for as a reverse takeover of Pubco by MMC North America. As a result of the Merger, there was a change in control of Pubco. In accordance with SFAS No. 141, “Accounting for Business Combinations” (“SFAS 141”), MMC Energy North America was the acquiring entity for accounting purposes. While the transaction is accounted for using the purchase method of accounting, in substance the transaction was a recapitalization of Pubco’s capital structure.
The total purchase price and carrying value of net assets acquired was $11,750. The Company did not recognize goodwill or any intangible assets in connection with the transaction. From January 1, 2006 until the date of the transaction, Pubco was an inactive corporation with no significant assets and liabilities. Effective with the merger, all previously outstanding membership interests owned by MMC Energy North America’s members were exchanged for an aggregate of 2,387,500 shares of the Company’s common stock. The value of the stock that was issued to MMC North America’s equity holders was the historical cost of the Company's net tangible assets, which did not differ materially from its fair value.
F-20
The total consideration paid was $11,750 and the significant components of the transaction are as
follows:
| | |||
| Common stock retained | $ | 11,750 | ||
| Assets acquired | (—) | |||
| Liabilities assumed | — | |||
| Cash paid | — | |||
| Total consideration paid/organization cost | $ | 11,750 | ||
In accordance with Statement of Position No 98-5 “Reporting on the Costs of Start-Up” (“SOP 98-5”), the Company expensed $11,750 as organization costs.
Financial Accounting Standard No. 109 requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statement or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between financial statements and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.
For the years ended December 31, 2007 and 2006, the Company generated, for federal income tax purposes, net operating loss carry forwards of approximately $4,725,901 and $4,528,036, respectively, expiring in 2026 and 2025 that could have been used to offset future taxable income. However, valuation allowances of $1,982,043 and $1,903,959 was recorded for the years ended December 31, 2007 and 2006 on the total tax provisions as the Company believes it is more likely than not that these assets will not be utilized during the next year. The United States federal, state and local net operating loss carryforwards are generally subject to limitations on their annual usage. Realization of the deferred tax assets and net operating loss carryforwards is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards. The amount of the deferred tax asset considered realizable, however, might be adjusted if estimates of future taxable income during a future period are expected.
F-21
The Company's income tax expense (benefit) from continuing operations consists of the following:
| | | ||||||
| Year Ended December 31, 2007 | Year Ended December 31, 2006 | |||||||
| Current | ||||||||
| US | $ | — | $ | — | ||||
| State | — | — | ||||||
| State | — | — | ||||||
| State | — | — | ||||||
| Local | — | — | ||||||
| Total current tax expense (benefit) | — | — | ||||||
| Deferred | ||||||||
| US | (1,417,770 | ) | (1,361,917 | ) | ||||
| CA | (267,959 | ) | (257,402 | ) | ||||
| NY | (124,291 | ) | (119,395 | ) | ||||
| Metro | (25,520 | ) | (24,514 | ) | ||||
| NYC | (146,503 | ) | (140,731 | ) | ||||
| Total deferred tax expense (benefit) | (1,982,043 | ) | (1,903,959 | ) | ||||
| Less valuation allowance | 1,982,043 | 1,903,959 | ||||||
| Total deferred tax expense (benefit) | $ | — | $ | — | ||||
| Total tax provision | $ | — | $ | — | ||||
The differences between income taxes computed using the statutory federal income tax rate and that shown in the statement of operations from continuing operations are summarized as follows:
| | | | | ||||||||||||
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2007 | % | 2006 | % | |||||||||||||
| Computed at US statutory rate | $ | (1,417,770 | ) | 30.00 | $ | (1,361,917 | ) | 30.00 | ||||||||
| CA | (267,959 | ) | 5.67 | (257,402 | ) | 5.67 | ||||||||||
| NY | (124,291 | ) | 2.63 | (119,395 | ) | 2.63 | ||||||||||
| Metro | (25,520 | ) | 0.54 | (24,514 | ) | 0.54 | ||||||||||
| NYC | (146,503 | ) | 3.10 | (140,731 | ) | 3.10 | ||||||||||
| Less valuation allowance | 1,982,043 | (41.94 | ) | 1,903,959 | (41.94 | ) | ||||||||||
| Total tax provision | $ | — | — | $ | — | — | ||||||||||
F-22
Components of deferred tax assets are as follows:
| | | ||||||
| Year Ended December 31, 2007 | Year Ended December 31, 2006 | |||||||
| Deferred tax assets | ||||||||
| Depreciation | $ | 558,641 | $ | 88,518 | ||||
| Net operating loss carryforward | 1,582,359 | 1,899,058 | ||||||
| Total gross deferred tax assets | 2,141,000 | 1,987,576 | ||||||
| Deferred tax liabilities | ||||||||
| Stock-based compensation | $ | 158,957 | $ | 83,617 | ||||
| State and local taxes | — | — | ||||||
| Total gross deferred tax liabilities | 158,957 | 83,617 | ||||||
| Less valuation allowance | (1,982,043 | ) | (1,903,959 | ) | ||||
| Net deferred tax assets | $ | — | $ | — | ||||
On January 25, 2008, the Company agreed to purchase two LM-6000 PC Sprint natural gas-fired turbines from GE Packaged Power, Inc, a subsidiary of General Electric, to be used in its Chula Vista Energy Upgrade Project, a 100 MW natural gas-fired power plant in Chula Vista, San Diego County, California.
The total purchase price for the turbines is approximately $31 million, to be paid in several installments through the expected delivery date in early 2009. The turbines are the primary equipment to be used in the Project, and will allow the Company to increase its capacity at the Chula Vista site, currently 44MW, as well as to greatly improve its efficiency and reduce its emissions generated per MW-hour.
On February 7, 2008, the Company and Karl W. Miller, the former President and Chief Executive Officer of the Company, entered into a Separation Agreement (the “Separation Agreement”).
Under the Separation Agreement, the Company paid Mr. Miller severance pay in the aggregate amount of $1,121,762 (gross), and is obligated to pay for the cost of Mr. Miller’s COBRA continuation coverage in the Company’s medical plan for eighteen (18) months. Such amounts are in lieu of and in full satisfaction of any amounts that might otherwise be payable to Mr. Miller under contract, plan or policy, including but not limited to his employment agreement dated May 15, 2006 (the “Employment Agreement”).
In consideration of the above payments, the Company and Mr. Miller agreed, among other things, that Mr. Miller would (i) release the Company from any and all claims and liability of whatever kind arising prior to February 7, 2008, including but not limited to claims relating to the Employment Agreement; (ii) transfer certain intellectual property rights acquired, created or maintained in connection with Mr. Miller’s employment by or association with the Company; and (iii) abide by certain non-competition and non-solicitation provisions set forth in the Employment Agreement. Under the Separation Agreement, the Company also agreed to release Mr. Miller from any and all claims and liability of whatever kind arising prior to February 7, 2008, with certain exceptions.
Also pursuant to the Separation Agreement, Mr. Miller agreed to resign from the Board of Directors of the Company, effective as of February 15, 2008. Such resignation was not based upon a disagreement with the Company on any matter relating to the Company’s operations, policies or practices.
F-23
There were no changes and disagreements with Accountants on Accounting and Financial Disclosure.
Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in company reports filed or submitted under the Securities Exchange Act of 1934, or the “Exchange Act,” is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include without limitation, controls and procedures designed to ensure that information required to be disclosed in company reports filed or submitted under the Exchange Act is accumulated and communicated to management, including our chief executive officer and treasurer, as appropriate to allow timely decisions regarding disclosure.
Management is responsible for establishing and maintaining adequate “internal control over financial reporting”as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting refers to the process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:
| (i) | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; |
| (ii) | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of our management and directors; and |
| (iii) | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements. |
Management has used the framework set forth in the report entitled “Internal Control — Integrated Framework” published by the Committee of Sponsoring Organizations of the Treadway Commission to evaluate the effectiveness of our internal control over financial reporting. Based on their evaluation, they concluded that our disclosure controls and procedures were effective as of December 31, 2007.
During the most recently completed fiscal quarter, there has been no change in our internal control over financial reporting that has materially affected or is reasonably likely to materially affect, our internal control over financial reporting.
This annual report does not include an attestation report of the company's registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by the company's registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management's report in this annual report.
None.
21
The information required by this item is incorporated by reference to our Proxy Statement for our 2008 Annual Meeting of Stockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2007. Our 2008 Annual Meeting of Stockholders of MMC Energy, Inc. will he held on Wednesday, May 28, 2008.
The information required by this item is incorporated by reference to our Proxy Statement for our 2008 Annual Meeting of Stockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2007. Our 2008 Annual Meeting of Stockholders will be held on Wednesday, May 28, 2008.
The information required by this item is incorporated by reference to our Proxy Statement for our 2008 Annual Meeting of Stockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2007. Our 2008 Annual Meeting of Stockholders will be held on Wednesday, May 28, 2008.
The information required by this item is incorporated by reference to our Proxy Statement for our 2008 Annual Meeting of Stockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2007. Our 2008 Annual Meeting of Stockholders will be held on Wednesday, May 28, 2008.
The information required by this item is incorporated by reference to our Proxy Statement for our 2008 Annual Meeting of Stockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2007. Our 2008 Annual Meeting of Stockholders will be held on Wednesday, May 28, 2008.
22
The following is a list of the Financial Statements included in Item 8 of Part II of this Annual Report.
Schedules not included herein are omitted because they are inapplicable or not required or because the required information is given in the financial statements and notes thereto.
The exhibits required by this item and included in this report or incorporated herein by reference are as follows:
| | |
| 2.1 | Agreement and Plan of Merger and Reorganization, dated as of May 15, 2006, between High Tide Ventures, Inc., a Nevada corporation, and MMC Energy North America, LLC, a Delaware limited liability company(1) | |
| 3.1 | Certificate of Incorporation of MMC Energy, Inc., a Delaware corporation(2) | |
| 3.2 | By-laws of MMC Energy, Inc., a Delaware corporation(3) | |
| 3.2(i) | Amendment to By-Laws(4) | |
| 10.1 | Form of Subscription Agreement among the Company and the investors in its private placement consummated in May 2006(1) | |
| 10.2 | Form of Registration Rights Agreement among the Company and the investors in its private placement consummated in May 2006(1) | |
| 10.3 | Split Off Agreement, dated May 15, 2006, among High Tide Ventures, Inc., Brent Peters, Douglas Smith, MMC North America and Leaseco(1) | |
| 10.6 | Employment Agreement, dated May 15, 2006, between MMC Energy, Inc. and Denis Gagnon(1) | |
| 10.7 | Form of Indemnity Agreement between the Company and the Company’s Directors and Officers(1) | |
| 10.8 | 2006 Stock Incentive Plan(1) | |
| 10.9 | Scheduling and Asset Optimization Services Agreement, dated June 7, 2006, between the Company and PPM Energy, Inc.(5)* | |
| 10.10 | Purchase and Sale Agreement between MMC Mid-Sun LLC and Kellstrom Commercial Aerospace, Inc.(3) | |
| 10.11 | Lease for principal office executed between Constitution Realty, LLC & MMC Energy North America(3) | |
| 10.12 | Assignment of lease obligation from MMC Energy North America, LLC to MMC Energy, Inc.(3) | |
| 10.13 | Energy Management Agreement, dated November 31, 2006, between MMC Energy North America LLC, MMC Chula Vista LLC, MMC Escondido LLC and Bear Energy L.P.(6)* | |
| 10.14 | Amendment No. 1 to the 2006 Equity Incentive Plan(7) | |
| 10.15 | Separation Agreement and Release, dated March 12, 2007, by and between MMC Energy, Inc. and Martin Quinn(8) | |
| 10.16 | Resource Adequacy Capacity Confirmation Agreement, dated January 23, 2007, by and between MMC North America, LLC and Occidental Power Services, Inc.(8)* | |
| 21.1 | Subsidiaries(9) | |
| 23.1 | Consent of RBSM LLP. |
23
| | |
| 24.1 | Power of Attorney (included in signature page) | |
| 31.1 | Certification by Michael Hamilton pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e), as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002. | |
| 31.2 | Certification by Denis Gagnon pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e), as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002. | |
| 32.1 | Certification by Denis Gagnon pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
| 32.2 | Certification by Michael Hamilton pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
| * | Portions of this Exhibit were omitted and have been filed separately with the Secretary of the Commission pursuant to the Company's Application requesting Confidential Treatment under Rule 24b-2 of the Securities Exchange Act of 1934. |
| (1) | Incorporated by reference to Current Report on Form 8-K filed May 15, 2006. |
| (2) | Incorporated by reference to the Definitive Proxy Statement on Schedule 14A filed August 22, 2006. |
| (3) | Incorporated by reference to the Quarterly Report on Form 10-QSB filed November 8, 2006. |
| (4) | Incorporated by reference to the Current Report on Form 8-K filed December 27, 2007. |
| (5) | Incorporated by reference to the Quarterly Report on Form 10-QSB filed August 15, 2006. |
| (6) | Incorporated by reference to the Annual Report on Form 10-KSB filed on March 6, 2007. |
| (7) | Incorporated by reference to the Registration Statement on Form SB-2 filed April 5, 2007 |
| (8) | Incorporated by reference to the Quarterly Report on Form 10-QSB filed May 15, 2007 |
| (9) | Incorporated by reference to the Registration Statement on Form SB-2 filed December 27, 2006. |
24
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
MMC Energy, Inc.
| By: | /s/ Michael J. Hamilton Name: Michael J. Hamilton Title: Chief Executive Officer |
Date: March 12, 2008
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Michael J. Hamilton and Denis Gagnon and each of them acting individually, as his or her attorney-in-fact and agents, each with full power of substitution, for him or her in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report, and to file the same, with all exhibits thereto and all other documents in connection therewith, with the SEC, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or his, her or their substitute or substitutes, may lawfully do or cause to be done or by virtue hereof.
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant in and the capacities and on the dates indicated.
| | | ||
| Signature | Title | Date | ||
| /s/ Michael J. HamiltonMichael J. Hamilton | Chief Executive Officer and Chairman of the Board of Directors | March 12, 2008 | ||
| /s/ Denis GagnonDenis Gagnon | Chief Financial Officer, Principal Accounting Officer and Director | March 12, 2008 | ||
| /s/ Richard BryanRichard Bryan | Director | March 12, 2008 | ||
| /s/ Frederick W. BuckmanFrederick W. Buckman | Director | March 12, 2008 | ||
| /s/ Peter LikinsPeter Likins | Director | March 12, 2008 | ||
| /s/ George Rountree IIIGeorge Rountree III | Director | March 12, 2008 | ||
| /s/ Phillip G. HarrisPhillip G. Harris | Director | March 12, 2008 |
25
