Thursday, September 22, 2016

#TBT: Islamic Project Finance: Structures and Challenges

This post is part of an occasional series highlighting a project finance article or news item from the past. It is often interesting and thought provoking to look back on these items with the perspective of months, years or decades of further experience. 

With this installment, we turn to an article written by Richard Keenan, a partner in Chadbourne's project finance group. It was first published in the February 2010 issue of the Project Finance NewsWire.

Islamic finance is expected to make up 30% of the total project finance market in the Gulf Co-operation Council, or GCC, countries by 2012, compared to just over 12.5% in 2006, according to the latest estimates.

However, growth in Islamic finance as a percentage of the total market continues to be constrained by certain obstacles. A significant proportion of Islamic finance that has been provided in connection with project financings in the GCC countries has been supplied through the “Islamic windows” of conventional banks rather than by Islamic finance institutions.

This article summarizes some of the Islamic finance structures typically implemented in project financings and looks at some of the challenges that have faced and still face the continued growth of Islamic finance in the project finance sector and how some of these challenges may be overcome.

The relationship between Islamic finance institutions and their customers is not the same as the conventional creditor and debtor relationship, but rather one involving the sharing in financial risks and rewards. Islamic finance is also principally asset-based and, in line with Shari’a principles of risk sharing, Islamic lenders bear some of the risks associated with ownership of the relevant assets. Applying these principles to project finance is difficult.
It is worthwhile describing briefly how an Islamic finance tranche is typically structured in a project finance transaction.

The most frequently used structures in the project finance sector in the Middle East are the Istisna’a-Ijara structure, which is sometimes generally referred to as a “procurement” structure, and the Wakala-Ijara structure.

An Istisna’a-Ijara structure incorporates an Istisna’a contract that applies to the construction phase of a project, and an Ijara contract is put in place for the operations phase.
An Istisna’a is a contract for sale whereby one party undertakes to manufacture a specific asset according to agreed specifications and deliver the asset by an agreed time for an agreed price.

If a traditional Istisna’a contractual arrangement was applied to a project financing, the financiers would enter into a contract directly with the contractors engaged to construct the project’s assets. To avoid the Islamic lenders being exposed to significant construction risk and the credit and performance risk of contractors, most project financings use a parallel structure where the borrower undertakes under an Istisna’a contract to procure the manufacture, delivery and construction of the relevant plant and equipment from the manufacturer. In parallel with the Istisna’a contract, the borrower enters into a construction contract with the construction contractor incorporating a pass through of the terms and conditions of the Istisna’a contract.The Islamic financiers make phased payments to the borrower, akin to draws under any conventional finance facility during the construction phase of a project. Some scholars have permitted the use of a forward lease arrangement, known as an Ijara Mawsufah Fi Al Thimma, whereby advance rental payments are paid by the borrower during the term of the Istisna’a. These advance rental payments are typically sized to cover the Islamic financier’s funding costs, together with a profit margin, and are often effected by a deeming provision whereby certain phase payments equal to advance rental payments are deemed to have been paid by the Islamic financiers to the borrower.
The use of forward lease arrangements is often permitted by scholars only on the proviso that if the borrower never has the benefit of a lease of the assets under the Ijara (for example, due to a failure to deliver the assets), any such advance rental payments must be reimbursed to the borrower. To avoid such an unacceptable outcome from the point of view of the Islamic financiers, if the Istisna’a is terminated prior to project completion, the borrower is obliged to pay liquidated damages for failing to deliver the assets equal to the aggregate advance rental payments paid by the borrower.

Title to the relevant assets typically passes to the Islamic financiers automatically upon transfer of title under the EPC or construction contract.

If the borrower fails to deliver the assets, the remedies available to the Islamic financiers are more or less the same as the remedies conventional banks rely on in the same scenario. The Islamic financiers are entitled to accelerate the repayment obligations of the borrower and to terminate the Istisna’a. The borrower is typically obliged to reimburse to the Islamic financiers the aggregate of phase payments it has received prior to enforcement and is often also obliged to pay liquidated damages as described above.

The Ijara contract typically comes into effect upon project completion. An Ijara, in simple terms, is a lease contract where a lessor purchases an asset and rents it to the lessee for a specific period of time at an agreed rental.

The leased asset must have a usufruct, or a legal right to use and derive profit or benefit from the asset. In order to be Shari’a compliant, an Ijara must be transparent, detailed and the terms agreed prior to execution. The lessor under an Ijara must maintain legal and beneficial ownership of the asset and bear responsibility for risks associated with ownership of the asset, meaning there must be a link between an Islamic lender’s ability to earn profits and the assumption of risk.

In the context of Islamic finance, the form of Ijara typically used is known as an Ijara-wa-iqtina’a; it includes a promise by the Islamic lenders as lessor to transfer the ownership of the leased asset to the borrower, as lessee, either at the end of the lease period or in stages during the term of the Ijara.

This form of Ijara is essentially the Islamic equivalent of a conventional equipment lease contract. Ownership of the assets is delivered to the Islamic financiers upon project completion pursuant to the Istisna’a contract and thereafter the Islamic lenders lease the assets to the borrower in consideration for rental payments that are sized to cover the capital cost of the equipment plus a profit margin.

The Istisna’a-Ijara documentation typically incorporates purchase and sale undertaking arrangements following termination or expiry of the lease. The Islamic lenders usually undertake to sell all or part of the assets to the borrower in the event of a partial or full cancellation or prepayment of the Islamic facility and following the discharge by the borrower of all outstanding payments owed to the Islamic financiers. After an event of a default by the borrower, the Islamic financiers normally have the benefit of a purchase undertaking from the borrower. This is a form of acceleration of the Islamic facility — the borrower in these circumstances is obliged to purchase the leased assets for a purchase price equal to the aggregate of amounts outstanding under the Islamic tranche. The documentation normally stipulates that title to the assets does not pass to the borrower until the amounts owed to the Islamic financiers have been discharged in full.

Obligations that would ordinarily fall to the Islamic lenders as owner and lessor of the assets, such as care and maintenance of the assets and responsibility for procurement of insurance, are normally performed by the borrower on behalf of the Islamic lenders pursuant to the terms of a service agency agreement. The amounts payable to the borrower in consideration for the performance of these obligations are normally recouped by the Islamic financiers as part of the rental payments payable by the borrower after delivery of the asset.
The Islamic financiers’ rights to take any enforcement action in relation to the assets is governed by the terms of an intercreditor agreement between the Islamic lenders and the conventional financiers.

A typical Istisna’a-Ijara structure is illustrated in the following diagram:

1   Construction phase (Istisna’a) — the borrower procures construction of project assets and then transfers title to assets to Islamic financiers. As consideration, Islamic financiers makes phased payments to the borrower (equivalent to loan advances).

2   Operations phase (Ijara) — Islamic financiers lease project assets to the borrower. Borrower makes lease payments (equivalent to debt service).

An alternative but similar structure often implemented in project financings involving an Islamic tranche is what is known as the Wakala-Ijara Mawsufah Fi Al Dhimmah structure or “Wakala-Ijara structure.”

This structure was used in connection with the Marafiq and Shuaibah IWPPs in Saudi Arabia.

Under this structure, the borrower is employed as the Islamic lenders’ agent or “Wakil” in accordance with the terms of an agency agreement known as a Wakala agreement. The Wakala agreement more or less fulfills the same function as an Istisna’a agreement in the other structure, although being an agency agreement, the contractual relationship between the Islamic finance institutions and the borrower is different. The borrower procures the design, engineering, construction, testing, commissioning and delivery of the assets identified in the Wakala agreement as the agent for the Islamic lenders.

The Istisna’a-Ijara and Wakala-Ijara structures are otherwise similar. They both incorporate an Ijara agreement for the operations phase and a service agency agreement pursuant to which the borrower performs certain obligations with respect to maintenance of the assets and procurement of insurance. The documentation involved in a Wakala-Ijara structure does not include separate purchase and sale agreements; however, the same rights and obligations of the parties with respect to transfer of assets at the end of the term or in the event of early termination are embodied in the documents.

What, then, have been some of the challenges affecting the integration of Islamic finance in the project finance sector?

A significant problem has been the difficulty that many Islamic financiers have had until recently competing with conventional lenders in terms of price and tenor.
Before the onset of the financial crisis in 2008, the pricing of project financings hit all-time lows and at these levels, project finance was not a particularly attractive proposition for many Islamic financial institutions. Pricing coupled with the length of tenors conventional lenders were able to commit to (up to 15 years in the oil and gas sector and over 20 years in connection with power and water transactions) made it very difficult for Islamic financiers to compete. Islamic financial institutions tend to focus more on retail banking and rely more on deposits as a source of liquidity rather than the longer-term bond market tapped by conventional banks.

A second obstacle for some Islamic financiers has been the risks associated with project finance.

A lot of time and effort have gone into the development of Islamic finance structures such as the Istisna’a-Ijara model in order to try to mitigate or eliminate risks to Islamic lenders. However, the remaining risks still make participation in these transactions prohibitive for many Islamic financiers.

As the legal owner of the project assets, Islamic financiers have exposure to third-party liabilities including environmental risk. Other obligations imposed on the Islamic lenders as owners of project assets include responsibilities relating to insurance and operation and maintenance of the assets. Under a typical Istisna’a-Ijara structure, these obligations are normally performed by the borrower on behalf of the Islamic lenders under a service agency agreement, and the borrower in its capacity as the service agent is liable for any loss or damage suffered by the Islamic financiers as a result of any failure to perform these obligations. However, notwithstanding the considerable effort that has gone into developing structures that transfer these risks to the borrower, the Islamic financiers still bear significant responsibility and risk as owners of the assets. The lenders often remain responsible for any capital improvements that are required and, although procurement of insurance is normally delegated to the borrower, the bottom line is that the Islamic financiers, as owners of the assets, bear the risk of availability of insurance and any vitiation by the borrower of its obligations with respect to the project insurance policies. Borrower indemnities to cover insurance shortfalls are of little value if the plant sustains serious damage or incurs significant third-party liability.

Add to these risks the standard risks that are always the concern of any project lender such as counterparty, technology and market risk and you end up with a risk profile that is too onerous for many Islamic financiers to take or results in the pricing of Islamic finance at levels that make it uncompetitive with conventional bank pricing.

A third impediment is, in the eyes of some Islamic finance experts and scholars, an incompatibility of some of the structures that have been developed with the principles of Shari’a.

Financial advisors, lawyers, Islamic financial institutions and their Sharia’a committees have spent a lot of time grappling with how to structure Islamic project finance in order to integrate Islamic finance with conventional finance. The end result of this has been the development of a somewhat cumbersome and document-heavy structure that in many respects mimics conventional financing (at least in terms of risk allocation).

What does the future hold for Islamic finance in the project finance sector, and how might some of the challenges faced by the sector be overcome?

In terms of pricing, the gap in margins between conventional and Islamic finance has more or less closed for the time being in the aftermath of the 2008 crisis in the international credit markets. However, the cost of borrowing from conventional banks is unlikely to remain as high as current levels in the medium to long term, and a pricing gap between conventional and Islamic finance will inevitably emerge again.

Looking ahead, there probably needs to be a greater recognition that Islamic finance and conventional finance are two different disciplines and that there will be price disparities between the two types of financing.

The disparity between pricing of conventional and Islamic finance is one of the drivers that has led to development of structures designed to put Islamic banks in more or less the same position as conventional lenders in terms of risk allocation. However, rather than implementing these structures or trying to “squeeze a square peg into a round hole,” as some commentators have put it, perhaps the way forward is to embrace more fully the principles of Shari’a underpinning Islamic finance. This could lead to the development of Islamic finance structures where the Islamic financial institutions play a more active role in discharging their responsibilities as owner of project assets rather than passing these onto to the borrower or third parties. In turn, this could lead to a greater willingness in the market to accept that the risk profile of Islamic finance justifies higher compensation.
There is an ongoing debate among experts and commentators as to whether the fundamentals of Islamic project finance need to be re-examined and new structures put in place.

It is no secret that the Islamic project finance market has been dominated by the “Islamic windows” of conventional banks. In fact the proportion of funding by purely Islamic finance institutions in the project sector is comparatively small. The one exception to this is Saudi Arabia where the Shari’a compliant finance institutions, meaning those Saudi financial institutions that do not offer conventional forms of finance — such as Alinma, Islamic Development Bank, Al Rajhi and National Commercial Bank — have made and continue to make a very significant contribution to the funding of project-financed transactions in the Kingdom. For example, of the US$1.5 billion loaned by Saudi banks in connection with the Rabigh IPP that achieved financial close in June 2009, 65% was contributed by Alinma, Al Rajhi and National Commercial Bank. The fact that Islamic finance structures such as the Wakala-Ijara structure have been accepted by Islamic financial institutions such as Alinma, Al Rajhi and National Commercial Bank and have withstood the rigorous scrutiny of their Shari’a committees has to be seen as a strong endorsement of these structures in terms of compliance with Shari’a principles. The outlook for Islamic project finance in Saudi Arabia is strong.

There undoubtedly needs to be a greater degree of consistency among the Shari’a committees of Islamic finance institutions regarding Shari’a compliance. The fact that you can have one particular Islamic finance structure or specific aspect of a structure approved by the Shari’a committee of one particular Islamic finance institution but not another is not helping the growth of this industry. A more standardized approach must be adopted not only to overcome a prevailing perception that the viability of Islamic finance continues to be hampered by uncertainty in terms of Shari’a compliance, but also in order to reduce the time and cost involved in executing Islamic project finance transactions.

The myriad legal documentation required to structure an Islamic finance tranche makes these transactions more expensive and more time consuming to execute compared to a conventional financing. Some recent initiatives have helped with market standardization. They include the growing list of industry standards published by the Accounting and Auditing Organization for Islamic Finance Institutions and Bahrain’s International Islamic Finance Market. However, more work and collaboration between Islamic finance institutions and their respective Shari’a committees is required.

There may also be a greater role to play for those governments of the GCC keen to foster Islamic finance within their countries. Some of the risks assumed by Islamic finance institutions could be mitigated by different forms of government protection. One example is a backstop against insurance risk. If, as owners of project assets, Islamic financiers are obliged to insure the assets, governments might offer backstop insurance protection to mitigate the risk of insurance not being available. This type of protection has already been provided by governments in favor of sponsors in relation to project financings in certain jurisdictions in the GCC, including Saudi Arabia and Abu Dhabi.

The enforceability of insurance provisions has been questioned by some Shari’a scholars on the basis that a contract of insurance has been associated with gambling, an activity proscribed by the Shari’a. Making the government the insurer of last resort could spur development of takaful (Islamic insurance) industries within GCC countries.
Government sponsors could also provide some degree of protection, third party or environmental risk through an indemnity or statutory relief.

There are also often tax implications for Islamic financiers with which governments of the relevant countries could assist. The ownership of project assets by the Islamic finance institutions and the contractual arrangements that they are party to often raise tax concerns for both sponsors and lenders. From the Islamic financiers’ point of view, taxes may be imposed in connection with the physical location of the asset or nature of the contractual arrangements — lease payments for example in some jurisdictions may be subject to withholding tax. From the borrower’s point of view, these structures can also be disadvantageous. Interest payments under conventional loans can be claimed as a tax deduction in many jurisdictions, whereas lease payments may not attract the same tax relief and, if withholding tax is levied on such payments, this liability is most likely to be passed onto the borrower through tax gross-up provisions. Governments in many of the GCC jurisdictions could do more to ensure that Islamic financiers and sponsors of projects that involve Islamic tranches are not any worse off from a taxation point of view than they would be if they were participating in a conventional financing.

Islamic finance is undoubtedly more suited to certain type of projects than others. Islamic finance lends itself more to projects that incorporate a discrete set of assets that can be owned by the Islamic financiers without too much potential intrusion on the enjoyment of such rights by conventional banks under intercreditor arrangements. Furthermore, to qualify for an Ijara contract, the assets owned by the Islamic financiers must be separable and have an economic value as stand-alone assets.

However, this can be a difficult proposition for plants that are made up of integrated equipment. While certain assets forming part of a plant may be capable of being “ring fenced” from the rest of the plant, such assets, if valued as individual items of equipment, may not reflect their true value in terms of their importance to the overall operation of the plant.

Finally, there is the issue of tenor. As with pricing, the competitive advantage in favor of conventional banks in terms of tenor they can offer has been to some extent eroded in the aftermath of the credit crisis, but it is difficult to gauge any advantage in the current market. Over the last 12 months, conventional banks have struggled to commit to tenors of more than eight to 10 years. This has resulted in the emergence of the “mini-perm” structure that was adopted, for example, in connection with the Al Dur IWPP in Bahrain. However, there are examples of project financings that have closed in the last 12 months where tenors of 20 years or more have been achieved. The Rabigh IPP in Saudi Arabia and Shuweihat 2 in Abu Dhabi are two examples.

It is difficult for many Islamic financial institutions to commit to tenors beyond seven to eight years. Some bankers have for this reason considered Islamic finance better suited for bridge financing. The market for equity bridge finance in the Middle East has contracted significantly over the last 18 months. Prior to the credit crisis in 2008, it had become more or less standard market practice for sponsors of project financings in the power and water sector in the Middle East to fund their equity contributions initially through an equity bridge loan. At the height of the market in 2006 and 2007, EBL tenors were as long seven years often not expiring until three or four years into the operation phase of a project. Depending on pricing, Islamic finance would in many in ways be ideally suited to equity bridge financing and if the market for this form of finance recovers, it may be worthwhile for sponsors, lenders and their advisors to try to attract Islamic finance institutions into this market.

Thursday, September 15, 2016

#TBT: Secrets of the Biodiesel Market

This post is part of an occasional series highlighting a project finance article or news item from the past. It is often interesting and thought provoking to look back on these items with the perspective of months, years or decades of further experience. 

With this installment, we turn to an article written by Todd E. Alexander and Marissa Alcala,  partners in Chadbourne's project finance group. It was first published in the November 2006 issue of the Project Finance NewsWire.

The ethanol market showed signs of cooling this fall because of falling oil prices and fears about overcapacity, but interest in new biodiesel plants remains hot.

Larger and larger biodiesel plants are being brought to market for financing. The projects are both new builds and expansion of existing facilities. Potential demand for biodiesel is also growing.

The distillate fuels market in the United States is currently 62 billion gallons a year, with potential for various blends of biodiesel throughout that market. The National Biodiesel Board reports that the maximum annual production capacity for US biodiesel plants in operation was 37.5 million gallons per year as of early September 2006. Of 86 plants in operation, only 20 have capacities of 10 million gallons a year or more. Thirteen of these existing facilities are adding additional capacity; the additions are currently under construction. The board said 65 new biodiesel plants were under construction in early September. Three of the new plants will have capacities of 80 million gallons a year or more. The largest has a capacity of 100 million gallons. Thirty two of the plants under construction have capacities between 10 and 80 million gallons.

As the demand for biodiesel increases, developers are turning to bigger projects in an effort to benefit from economies of scale. Banks and private equity funds are helping the construction boom by providing funding for ever larger projects.

Any developer seeking financing should secure a strategically located site and negotiate a solid technology and construction contract before approaching potential lenders and equity investors.

Site Logistics

Because the operating costs for biodiesel plants tend to be fairly comparable regardless of the technology employed, one way a developer can stand out from the pack is site logistics. The key to a strategic site is to find one that reduces costs and increases flexibility.

Site location can have a significant impact on costs. For example, putting a plant close to a reliable source of feedstock will decrease transportation costs on the supply side. Siting a plant close to a committed offtaker or sizable blending market will help reduce transportation costs for offtake and delivery. A site near an active port or other water- way will reduce overall transportation costs because of the comparatively low cost of barge and other water-based trans- port (particularly when compared to transport by rail or road). The greater the number of destinations that a plant can access easily, the greater the ability a developer will have to manage feedstock supply and offtake to maximize profit at any point in time. Direct access to water also means direct access to the export market, making a facility less reliant on industry growth within the United States.

Construction Contracts

Developers often enter into turnkey construction contracts with a fixed price, guaranteed construction schedule and guaranteed performance level upon completion in an effort to reduce construction risk. Lenders usually require such a turnkey contract as a condition to funding. A project will cost more to build under a turnkey contract; the contractor will charge more in exchange for taking on more risk. The contractor usually agrees to cover the developer’s fixed costs if there is a delay in construction. It also agrees to compensate the developer for lost value if the completed plant does not meet guaranteed performance levels. In a project finance transaction, these guarantee payments will be used to pay interest during a construction delay or, in the event that performance guarantees are not met at completion, to buy down the debt.

The number of contractors who will sign turnkey contracts to build biodiesel plants in the United States is small. These contractors include Lurgi PSI, Fagen, REG and Safer Energy. Because most of these contractors also build ethanol plants, they should be familiar with the standard turnkey provisions that lenders require. However, given the small pool of potential contractors, delays are to be expected in getting on a contractor’s master schedule, and the actual schedules, once a project is listed, are elongated. Contractors are also using the high demand for their services to charge premium fees.

A non-turnkey contract can be used if the equity investors are comfortable taking construction risk. The project would have to be financed either with all equity or with debt backed by significant sponsor-completion support. The developer could arrange for a single contractor to build the facility without any performance guarantees, or arrange for various components to be provided by multiple contractors. The latter approach, often referred to as an owner-construct process, places an additional burden on the developer of managing the construction timeline and supervising multiple contractors. In exchange for this additional responsibility, the developer may be able to build the plant at a lower cost.

Developers also need to obtain rights to the process technology that will be used in the plant. In a turnkey arrangement, a technology license is incorporated into the construction contract or provided in an accompanying license agreement. In an owner-construct structure, the developer must sign a license directly with a biodiesel process technology provider.

Seeking Equity

Biodiesel developers usually use one of two approaches to raise equity. The first is to do a private placement of shares or other equity interests in the project company. The second is to solicit proposals from a limited number of private equity firms, and select an investor through a competitive bid process.

Factors to consider in a bid process include timing, what, if any, preferred return the private equity investor will require, the carried interest to the developer, the degree of control the equity investor will insist on over the project and advisory or ancillary services. In some cases, a private equity firm might offer to provide both equity and subordinated debt. Such subordinated debt is typically priced in the range of 12% to 18% and might also include warrants in favor of the subordinated lenders for conversion to equity.

All equity investors look for strong projects with projected rates of return around 25%. Solid supply and offtake contracts with competitive pricing and dependable, experienced counterparties will help make a project more attractive. Equity investors may also be interested in multi-plant opportunities with the same developer.

A private placement would be expected to attract a larger number of small investors, and would draw investment based on expected returns with the developer’s management team running the project. The carried interest to the developer would be determined in advance by the developer and identified in the placement memorandum. A developer using this approach usually retains more control over the project, but ends up with a smaller carried interest than in a private equity scenario. A private placement typically takes more time to execute than an auction involving just a few private equity houses.

It is usually faster to raise money from just a few private equity funds. Private equity management teams often bring valuable expertise and contacts to the table that may be of particular benefit to developers with less business experience. This can lessen the day-to-day burdens on the developer team. A developer may need to engage a financial adviser to make introductions and facilitate the review of proposals. Such financial advisers typically charge a finder’s fee of between 4% and 7% of the equity raised from their efforts.

Private equity investors tend to have a shorter investment horizon than investors who buy equity offered through a private placement. Private equity firms usually want to hold an investment only for a few years before exiting. A private equity investor might sell its interest in a biodiesel facility to another private equity fund, to an interested company or, less frequently, to the original developer or company management. Another exit strategy that can be attractive to both private equity and other investors is to take the biodiesel company public eventually through an initial public offering. Many private equity firms would be interested in “master limited partnership” structures where a biodiesel company has units that are traded on a stock exchange or over-the- counter market. This would provide liquidity and make for an easy exit. It would also bring down the cost of equity to developers. Such structures have been slow to develop.

Regardless of approach, equity can always be split into different classes with various rates or priorities of return, as well as varied levels of voting or management rights. The right structure for each project will depend in part on timing and on the preferences of the developer and initial project sponsors. Developers can generally expect to maintain a carried interest in the range of 15% to 20%, with higher numbers in some exceptional cases.

Raising Debt

To date, most financing for biodiesel plants has come from Midwestern banks in Minnesota and Iowa. However, lenders with experience with ethanol are showing a growing interest in biodiesel projects. With the significant growth in biodiesel production anticipated in the next few years, money-center banks are also expected to enter the market.

Because the biodiesel lending market is still relatively immature, developers should expect biodiesel financing terms to be more conservative than current ethanol financing terms. In particular, developers should expect lower debt-to- equity ratios (i.e. more equity and less debt). Midwestern banks are usually lending to biodiesel projects at a 1:1 debt-to- equity ratio. As is the case with ethanol financings, developers should also expect significant cash sweeps that protect the lenders against downside risk. While a 7- to 10-year term for biodiesel financing is common, lenders typically size cash sweeps that, if realized, would reduce the total life of the debt by two years or more.

Lenders evaluating biodiesel projects obviously focus on the expected returns and health of the project while the loan will be outstanding, but they also want the project to look healthy for a few years after the loan is expected to be repaid to provide a cushion in the event of delays or other complications. Lenders focus in particular on the supply of feedstock. There is a limited number of crushing facilities in operation currently, and ownership of them is concentrated in the hands of only a few companies. Lenders will insist that a project have a significant amount of working capital. There are long lead times between payment for feedstock from a crushing facility or importer and when the feedstock is delivered. Working capital could be borrowed as part of the debt principal, addressed through longer or more flexible payment terms, or provided by a strategic partner or separate lender. Banks usually offer working capital equal to 50% to 80% of the accounts receivable and inventory of the project.

Lenders also expect developers to have a commodity hedging strategy to shield the project from volatility in biodiesel and feedstock prices. In addition to traditional hedging arrangements, developers can also control prices by entering into long-term fixed price contracts or by entering into tolling agreements where the biodiesel producer is paid a flat fee for turning feedstock into biodiesel. Some producers have also been able to secure offtake contracts with prices indexed to heating oil or ultra-low- sulfur diesel.

Other mitigants that help attract lenders to the biodiesel industry include the use of equipment in biodiesel plants that lets the producer switch among various feedstocks depending on which is the most economic at any given time. This flexibility puts biodiesel in a unique position to weather fluctuations in feedstock pricing and availability (particularly compared to ethanol plants that usually require major plant or process modifications in order to switch feedstocks). As an export market develops for US biodiesel, this will also help make lenders more comfortable because of the flexibility it affords for dealing with changes in the US market. Use of biodiesel as a replacement for fuel oil in power plants would open a new segment in the offtake market; plans are underway to test the viability of biodiesel in power plants in the northeastern United States.


Just like in any project, there are risks that must be managed and monitored.

The US government offers a tax credit to blenders as an incentive for using biodiesel. Blenders can get a credit of $1 per gallon for blending agri-biodiesel (diesel fuel made from virgin oils derived from farm commodities and animal fats) or 50¢ per gallon for other biodiesel made directly from agricultural products and animal fats (sometimes called brown and yellow grease). Some market observers believe biodiesel consumption in the US depends on this blender’s credit, at least outside states where biodiesel blending is required by law. The credit expires at the end of 2008. While there is risk that the blender credit will not be extended by Congress, most in the biodiesel industry are confident that it will be continued beyond 2008 in some form. Selling into a healthy export market may help to mitigate part of this risk.

Biodiesel prices fluctuate. Most biodiesel facilities are uneconomic to operate if wholesale prices for petro- diesel drop below $1.20 per gallon. The price for petro- diesel is a factor in what can be charged for biodiesel. However, there is no correlation between petro-diesel prices and prices for feedstock used to make biodiesel. This leaves plants exposed to being whipsawed if biodiesel prices drop at the same time that feedstock prices remain high. Use of one or more of the hedging strategies discussed earlier, together with the opportunity to switch feedstocks to get the best market price, is the best way to mitigate this risk.

Another risk is the potential harm caused by poor quality biodiesel making it to market. When the 2% biodiesel blending requirement first went into effect in Minnesota, unanticipated quality problems slowed acceptance of biodiesel and required that temporary waivers of the blending requirement be granted. The industry must ensure that biodiesel meets required production and performance standards, including cold flow properties, to succeed. To help address quality concerns, the National Biodiesel Board started a BQ-9000 accreditation program for producers and marketers of biodiesel. This is similar to the steps that wineries have taken with appellation controlee laws to guarantee quality. Many expect biodiesel eventually to become unmarketable without BQ-9000 accreditation.

The biodiesel market is still evolving, with rapid growth now being led by many of the large ethanol producers such as ADM and Cargill. Individual projects are getting larger. More banks are crowding into the market as potential lenders. This helps borrowers, but at the same time, the trend is also toward increasing complexity in loan arrangements.

Thursday, September 8, 2016

#TBT: The Challenges Facing Renewable Energy Developers in Emerging Markets

This post is part of an occasional series highlighting a project finance article or news item from the past. It is often interesting and thought provoking to look back on these items with the perspective of months, years or decades of further experience. 

With this installment, we turn to a transcript of a panel moderated by Todd E. Alexander, a partner in Chadbourne's project finance group. It was first published in the November 2010 issue of the Project Finance NewsWire.

Chadbourne hosted a workshop for the multilateral lending and export credit agencies on renewable energy projects in emerging markets in September in its offices in Washington. The workshop covered a lot of ground. The following is an edited transcript of a panel discussion among three developers whose companies are working on renewable energy projects in Africa and Asia. The panelists are Aparna Rao, vice president of AES Africa Power Company, Brian Kubeck, senior vice president for development at Sithe Global Power, and Jim Scarrow, director of legal affairs for the Americas at SunEdison. The moderator is Todd Alexander with Chadbourne in New York.

MR. ALEXANDER: Aparna Rao, do you see much difference in how multilateral lending agencies like the International Finance Corporation and other lenders view a renewable energy project compared to a conventional power plant?

MRS. RAO: I think they use the same standards. The motivation for investing in a country and the reasons the country is looking at renewables are very important. Both they and we pay close attention to the electricity sector framework.

MR. ALEXANDER: Is it your experience that the agencies do not seem as eager to finance power plants that use fossil fuel today as they are to finance wind farms and other renewables projects? For example, we worked recently with an export credit agency that is making it easier to finance small renewables projects by scaling back the level of diligence and working toward expedited closings.

MRS. RAO: I don’t think we get better pricing for renewables projects than other types of power plants, but the multilaterals seem willing to get involved at an earlier stage. The cost structures in some of these countries are front loaded in the sense that there are additional high costs to build transmission lines and other basic infrastructure that get rolled into the project cost. What might start as a 50-megawatt project can end up with the cost structure of a 300-megawatt project. 

In some cases, there may be a clean investment fund set up by the agencies to help fund developers.

I would encourage banks and particularly multilaterals, because they have traction with the governments, to find innovative ways to lend directly to local banks who, in turn, might fund developers and share the development or country risk.

MR. ALEXANDER: Brian Kubeck, do you see much difference between the level of diligence and the allocation of risk in renewables projects compared to conventional power plants?

MR. KUBECK: We don’t see much difference in terms of diligence. It is dangerous to cut corners. What we have seen is a potential for tension between the agencies and governments in some of these countries. The agencies are keen to do projects that fit into a larger strategy for reducing carbon emissions. That motivates the multilaterals to watch the carbon so carefully that it can create friction with governments whose countries are still at a stage where they really need to find the least-cost alternative.

The two goals can be integrated in the longer term, but the priority in these countries has to be economic development, and it is hard for a country at an early stage of development to put all its eggs in the renewables basket.

I like Aparna’s idea of trying to work through local banks. Funding resource studies for renewables is a huge risk for a developer. It is difficult to mobilize all of your resources for smaller projects, which renewables tend to be, and to go into a country, for example, solely to develop a 20-megawatt solar plant. The resource work is the highest risk capital when you go in to measure the wind or sunlight.

If the multilaterals can work in advance with governments to get some of those resource studies off the ground, that would speed development. You need at least a couple of years of data to be able to finance a project. It is tough for a developer to go into some of these countries and say, “I am going to fund resources studies in the hope that I will have a project on which to start working in two years time, and I hope in the meantime that the regulatory regime firms up so that we can have a financeable project.”

MR. SCARROW: I have a slightly different perspective. SunEdison operates and installs PV systems around the world, and one of the benefits of solar in emerging markets is the data.
In the US, we have very good sun data. The sun, as it turns out, is extremely reliable. In the US, we know where the sun is going to shine. It is variable during any 24-hour period, but over the course of a year or two years, we nail it. We have closed a billion dollars in solar financings over the last few years. The toughest part is educating banks, and I am talking now about New York banks. We are just becoming more acquainted as a company with the multilaterals.

The risk profile for a solar photovoltaic project is different than for a wind farm. We both use P50 and P90 numbers to project output. P50 means there a 50% chance that the project will generate more than projected output and 50% chance that it will generate less. P90 means there is a 90% chance of doing better and only a 10% chance of doing worse.
For a wind farm, the difference between the two projections can be fairly significant.
For solar, the difference is something like 3% or 4% of cash flow. Irradiance data in emerging markets is pretty reliable, even though it is not as reliable as in the US.
Contrary to the conventional wisdom, we don’t need two years of data to go in. We are diving into emerging markets very quickly. I think our challenge is almost the same internationally as domestically -— to convince lenders that this is reliable technology and that the data is credible.

Moving to another point, one thing we do run across is that once a solar system is installed, there are no moving parts and very little maintenance is required. We monitor the equipment through wireless communications. People sit in our Sacramento office and can tell you within 10 minutes when any string of panels around the globe shuts down. We are able to monitor everything internationally from one location.

The significance is there are not a lot of jobs. One of the challenges we have in fact, whether it is with stimulus programs in the United States or talking to governments internationally, is these countries are interested in jobs first. Energy security is a secondary concern.

Where solar could produce jobs is in local manufacturing, so that is what we are seeing. To the extent a government wants a jobs program, you see solar panel factories being built—not just in emerging markets but also in places like Canada. The feed-in tariff in Canada has domestic content requirements and has been very successful. There are huge amounts of investment going into Ontario for solar facilities.

MR. ALEXANDER: Samsung alone committed to an $8 billion investment in Ontario. Do you think you receive preferential treatment from the host country because you are trying to bring green energy or are you treated the same as if you were building a coal-fired power plant?

MR. SCARROW: We get very good receptions internationally. The same is true in the US. For example, we are installing a large solar facility in North Carolina. Sometimes it is surprising how receptive communities are to solar. I had thought when they see the back 40 acres being covered in blue pieces of glass, they would go through the roof. But either it is good fortune or it is North Carolina, but we have been welcomed everywhere.

MRS. RAO: Just to return to the resource mapping initiative, in India, the solar division of the National Renewable Energy Laboratory is conducting studies everywhere and it has released maps already for, I believe, the northern and western parts of India. Our solar group is following on the heels of where maps are released. It just secured a power purchase agreement in one of these areas.
Various agencies are working on resource mapping, but it is not a very well coordinated approach or the data is not always made widely available. Another challenge in some of these countries is the governments appear to hand out licenses to anyone with a telephone and you get essentially a large number of local science projects.

MR. KUBECK: I agree with what was said about solar data. However, it is still a good idea to have at least a year of on-site collection.

The more challenging area involving data is geothermal. The problem is that it is like drilling for oil. A lot of money must be spent to prove the resource.

Turning to the reception in developing countries, India is going to be very successful in solar because it has invested in the manufacturing end of the business. But when you get to smaller countries that are really in the early stage of development, manufacturing is not an option. For them, whether to install solar comes down to questions of reliability and cost. Jumping on the green bandwagon for the sake of being green is not always the best approach.

Small Scale

MR. ALEXANDER: Scale is another challenge in the developing
world. You may not be able to do a 200-megawatt wind farm. There isn’t the infrastructure to accommodate it.

MRS. RAO: I think it makes sense for a private developer to go into a country where it is possible to build a pipeline of projects that aggregate to 150 or 200 megawatts. We are not opposed to doing a series of smaller projects. In Tanzania, for example, I believe the World Bank supports an 8.5¢ per kWh subsidy for projects that are less than 20 megawatts in size.

MR. ALEXANDER: Many of these projects are not competitive with coal or gas, at least at this time. Some countries have feed-in tariffs to support renewables. How worried are you that the law might change as it did in Spain and Germany? How much risk is there in a country that is struggling to decide whether to support renewables or put food on the table?

MR. KUBECK: There is a crowded graveyard of developers who said, “I have a good contract, and that’s all I care about.” We need to feel the project fundamentally makes sense for a country. The subsidy might be provided through the financing, making it less susceptible to change. The burden does not have to fall entirely on the country’s shoulders. For example, the subsidy might be in the form of carbon credits.

MR. SCARROW: Let me come back to the question of scale. I came from Chadbourne where I worked on very large projects. When I got to SunEdison and someone asked, “Jim, can you help with this big project? It is 15 megawatts.” I thought, “Are you kidding me? Is that before construction?” My perspective has changed. To give you a very rough rule of thumb because prices are all over the map, it costs about $5 million a megawatt of installed capacity for solar PV. The company started with solar systems on roofs of big box stores like Walgreens, Best Buy and Wal-Mart. A small Walgreens system would be on the order of 30 kilowatts. A big Staples distribution center, meaning a warehouse, might be one megawatt. The challenge when working on projects on this scale is to come with efficient financing structures. We have done a good job in the US coming up with structures whose transaction costs don’t bury us. Internationally that becomes more of a challenge. We are a subsidiary, as of last November, of MEMC, which is a semiconductor manufacturer with a global footprint, particularly in Asia. Our projects are coming in from many sources. We are particularly active in India. The challenge is to find $2.5 billion to build lots of very small projects. Change in law risk is significant. We saw the markets close in Germany and Spain. Then the market sort of re-opened in Germany and, suddenly, all of the panels in the world gravitated towards Germany again, driving up prices everywhere else. Italy is our most active international market today where the changes in law are working in the market’s favor. We are building a 70-megawatt project outside Venice, which I think will be one of the larger PV projects in the world until we get leap frogged by someone else.

Screening Projects

MR. ALEXANDER: How do you recommend developers screen projects?

MR. SCARROW: You can’t get to a meaningful size just screening 4,000 small projects as they come in the door. You need to find a way to make the utility the ultimate credit behind the deal. That’s the only way in some countries to do financings on a large scale.
MR. ALEXANDER: Aparna, how does AES get comfortable in countries where it has to charge more for electricity than competing suppliers using fossil fuels? The project is not economic without some form of government support. That support can be pulled away.
MRS. RAO: It boils down to how strongly motivated the country is to move to renewable energy. A credible motivation in richer countries is a drive for energy security and for alternatives to continuing to deplete scarce natural resources. When you are screening countries, it is very, very important to understand what is driving them. A general interest in being green and keeping people happy does not translate into a stable regulatory framework.

MR. ALEXANDER: Does involving a multilateral lending agency or export credit agency in the financing give you any legal protection?

MRS. RAO: We often take advantage of political risk guarantees from the agencies. I am now speaking more broadly than just renewable energy development. Political or civil unrest does not necessarily make a project more likely to default on its financing. For example, in Côte d’Ivoire, the government has never defaulted on a payment despite the civil unrest over the past decade, and you find examples like this elsewhere. The fact that a country has had to borrow from the International Monetary Fund instills some fiscal discipline.

MR. ALEXANDER: Brian Kubeck, how important is it to have a savvy local partner?

MR. KUBECK: Boots on the ground are critical. We need a local partner whom we trust. Screening local partners is no easy task. It often takes a year or more to find someone with whom you can really get comfortable. We have had projects on which we have spent a lot of money and time and, six months in, we end up with concerns about whether our local partner is complying with the Foreign Corrupt Practices Act. That sort of behavior from a local partner is a non-starter, no way, no how, no benefit of the doubt. If we have any doubt, we don’t proceed, so that’s a challenge. It is hard for us to justify spending time on a project that is less than 200 megawatts in size. It can be a pipeline or a couple different types of projects, but if we are going to invest development capital and take the time to vet a local partner and put our own team on the ground for a long period of time, it has to be a large opportunity.

MR. ALEXANDER: Jim Scarrow, in the next five years, what do you think are the biggest growth opportunities overseas?

MR. SCARROW: Asia and South America. We are keeping an eye on Chile and Peru, although those markets are not yet ripe. Solar, like most renewables, requires some form of government inducement. There are plenty of inducements in the developed countries. We are in India, Malaysia and Thailand. In South America, we are not seeing the fundamentals in place yet where a lot of the existing capacity is in cheap hydroelectricity.

MR. ALEXANDER: Brian Kubeck, where are the greatest opportunities for Sithe?

MR. KUBECK: Hydroelectric projects are a no-brainer. After that, we think geothermal is poised for growth. Those are the projects that we think make the most sense if we can figure out a way to get the resource studies financed at an acceptable level of risk.

MR. ALEXANDER: Aparna Rao?

MRS. RAO: My focus is in Africa. I think we are looking harder in eastern Europe for PV solar and some in South Africa. For wind, the growth will be largely in China. China is a very good example of what we have talked about earlier in terms of government support and having extremely good coordinated efforts among developers, offtakers and regulators and providing innovative financing packages such as financing for turbines. Obviously the turbines are manufactured in China, and it is all local content, but our experiences in China have been good for wind projects. Returning to Africa, geothermal is looking like a good resource, especially in east Africa.

Thursday, September 1, 2016

#TBT: Investing in Negawatts

This post is part of an occasional series highlighting a project finance article or news item from the past. It is often interesting and thought provoking to look back on these items with the perspective of months, years or decades of further experience. 

With this installment, we turn to a transcript that was first published in the Project Finance NewsWire in February 2013 written by James Berger, an associate in Chadbourne's project finance group.

Many financial institutions are trying to figure out ways to invest significant amounts of capital in energy efficiency as government incentives expire for renewable energy. Because it is often less expensive to avoid consuming a megawatt of energy by increasing efficiency than to build the generating capacity necessary to produce the same megawatt, energy efficiency investments promise attractive financial returns. 


However, there are several obstacles to such investments. 

One obstacle is the high upfront capital costs. More efficient equipment is often more expensive than less efficient equipment. Retrofitting a building can be prohibitively expensive for the building’s owner. Many homeowners or building owners are reluctant to make investments that can take years to show a return or else they have higher priority uses for their capital. 

Another obstacle is uncertainty about the amount of savings. While it is easy to calculate how much energy a piece of equipment or a building uses, it is much more difficult to calculate how much energy has been saved as a result of an energy efficiency upgrade. Standardizing protocols and models for accurately predicting and measuring the energy savings of different energy efficiency investments is important to create accurate financial models.

Another obstacle is most energy efficiency investments are illiquid. The lack of an easy or quick exit prevents many would-be investors from participating in this market. Tradable financial assets backed by energy efficiency improvements might be able to find a more ready market than direct investments in the underlying energy efficiency improvements.
Another challenge is scale. Upgrading the energy efficiency of a whole commercial building will always be a smaller investment than building a utility-scale wind or solar project. The low-hanging fruit of energy efficiency could provide billions of dollars of investment opportunities and very attractive returns, but it will require taking a page out of the books of residential solar companies that package portfolios of small rooftop solar installations to finance in master financing facilities in order to lower transaction costs and reduce risk through diversification.

Several different strategies for financing portfolios of energy efficiency investments have emerged.


Residential PACE (or property assessed clean energy) financing is used to install renewable energy systems such as solar panels on a residential roof and make energy efficiency improvements in a home. 

Pursuant to special legislation, a local municipality borrows money in the capital market by issuing bonds. The municipality then lends the proceeds of the bond offering to homeowners who want to install renewable energy equipment or make efficiency improvements. In some cities, water conservation measures can also be funded. The homeowner repays the loan through a special property tax assessment that attaches to the property.

This addresses the problems of high upfront costs as a deterrent to make improvements. Loans to homeowners can run as long as 20 years. The loans are also on favorable terms because the municipality can borrow more cheaply than the homeowner can. The loan amount is based on the tax capacity of the property rather than the homeowner’s credit. 

The obligation to repay the loan transfers to a purchaser if the property is sold. This allows a homeowner to decide whether to make improvements without worrying whether they will pay off before selling the home.

PACE loans effectively subordinate all other lenders’ security, because the PACE loan is repaid as part of the property tax assessment, which is superior to all other obligations. This means that mortgage lenders end up subordinated to the municipality. 

In 2010, the Federal Housing Finance Agency, which regulates Fannie Mae and Freddie Mac, issued a statement indicating that it would not allow PACE loans to take priority over mortgages that are federally insured. Most PACE programs have had to be suspended as a result. Some states have subsequently passed legislation that removes the senior lien status and leaves PACE loans in a subordinated position to mortgage holders.

Currently 28 states and Washington, DC have passed legislation permitting PACE financing. 
Commercial PACE programs have been implemented in California and Colorado. The structure of the commercial programs is similar to the residential programs: a municipality issues bonds and the proceeds are borrowed by building owners to install renewable energy systems or make energy efficiency upgrades. A key difference is that mortgage holder approval is required. In addition, the Federal Housing Finance Agency’s stance on residential PACE programs does not apply to commercial PACE programs.

The financing potential for commercial PACE is huge, with an opportunity to invest $88 to $180 billion in improvements to large commercial buildings alone. 

There are three types of bonds that can be issued under commercial PACE programs. A pooled bond is where applications are aggregated and a revenue bond is issued to fund proposed projects. A stand-alone bond can be used for very large projects. This is when a revenue bond is issued to fund an individual project or a small number of substantial projects. Finally, an owner-arranged bond is where an owner arranges project financing with a private lender and the lender accepts a PACE-like repayment arrangement.

Only a limited number of residential and commercial PACE bonds have been issued to date in California, Colorado, Minnesota and Ohio in amounts ranging from $40,000 to $9.75 million. Resolving the subordination issue and the Federal Housing Finance Agency’s objections, as well as increasing awareness and the volume of issuances is important to this market. Commercial PACE can expand once more states pass the appropriate legislation.


Despite securitization’s bad reputation in the wake of the financial crisis in which securitized residential mortgages played a large role, many types of loans, such as auto and credit card loans, are still regularly securitized and sold to investors. There has been talk for months about the securitization of residential solar system leases and power purchase agreements. 
Some investors are now looking at securitizing portfolios of energy efficiency loans, including PACE loans. 

Securitization of such loans would work like any other traditional securitization. First, a bank or other financial institution would pool energy efficiency loans by purchasing them from lenders. Next, the bank would engage a loan servicer and segregate the pool of loans into discrete pools of assets that reflect differing categories of risk. Notes secured by the receivables from these pools of assets would then be marketed and sold to third-party investors. This model could give large investors a relatively safe investment that returns a specified interest rate while also giving the original lenders new capital with which they can make new loans.

Securitization of energy efficiency loans may remove some of the obstacles associated with investing in energy efficiency. First, securitization would make a fresh source of capital available to lenders. Second, it would provide a liquid market for investors, which could attract more capital to the market.

Determining the risk of default of the underlying loans is a hurdle that must be overcome. The risk associated with PACE loans is low in cases where the loans have a senior lien on the property associated with the loan. For non-PACE loans that do not have a senior lien, the risk of default would have to be based on the creditworthiness of the borrowers. There are not enough years of data on default rates. 

Because securitized energy efficiency loans will be backed by the receivables of many different loans, creating standardized protocols and methods for determining the savings from certain energy efficiency investments is very important. The securitization model rests on being able to pool loans based on risk and return. 

Some bankers expect that the first round of securitized energy efficiency loans will hit the market in 2013.

Fund Arrangements

Larger projects are needed in which to invest to provide the market with opportunities for scale. With fewer and larger projects, there will be lower transaction costs and, theoretically, a higher return. 

Investment funds, which can aggregate tens or hundreds of millions of dollars of investable capital, can make large energy efficiency investments using one of two similar arrangements.

One arrangement is an energy savings performance contract where an investment fund serves as an intermediary between a building owner and a service provider who installs and, to the extent necessary, operates and manages energy efficiency upgrades. The investment fund provides the financing for the improvements and owns them, usually through a special purpose entity used for a specific energy efficiency project. This only works for large projects. 

The building owner agrees to pay the investment fund a regular service charge that will repay the investment as well as provide a return on the invested capital. The service charge is an amount per unit of avoided energy. This arrangement protects the building owner from ever paying more per month for energy than before the parties entered the contract.

The investment fund enters into an agreement with a service provider that will make the energy efficiency upgrades and be responsible for ongoing monitoring and maintenance. Continuous monitoring is needed to measure the energy savings. In some transactions, the agreements with service providers include a performance guarantee to ensure specified energy efficiency targets are met.

An alternative to pricing based on energy savings is to use a managed energy services agreement where the investment fund pays the building owner’s on-going utility bills directly and charges the building owner a fixed monthly fee equal to the building’s historical energy rates, adjusted for occupancy and weather-related variables, both of which must be negotiated and agreed upon prior to entering the transaction. Obviously, the fee charged must be less than what the building owner is paying currently for utilities for the arrangement to be attractive.

The investment fund generates revenue by capturing the difference between the building’s old energy costs and its decreasing energy costs as the building is made more efficient over time.

An advantage of a managed energy services agreement is that it reduces diverging incentives in multi-tenant buildings where the building might have an incentive to pocket the savings from the efficiency improvements while charging tenants full cost for utilities. This will not maximize reductions in energy usage. In addition, because repayment in managed energy services agreements is tied through the utility bill, the risk of tenants or building owners failing to make a payment is reduced (when compared to energy savings performance contracts) because the tenant or building owner will have to pay the bill to keep the lights on or the hot water running.

Both types of arrangements typically provide an option for the building owner to purchase the equipment or other upgrades at the end of the contract with the investment fund. The owner of improvements can depreciate them, and many types of improvements also qualify for tax credits. The building owner cannot be expected at inception to exercise any purchase option or the investment fund will not be considered the tax owner of the improvements. The fund will also have a hard time claiming tax ownership of any improvements that cannot be removed and deployed economically at the end of the contract term. The contract must not be so long as to mean that the improvements have been dedicated to the building owner for substantially their entire economic life. Inability to claim tax ownership may not be fatal; it just affects the economics. 

Both of the arrangements described earlier are new with only minimal track records. The kinds of investors that would invest in a typical investment fund may not be willing to invest in a fund that makes energy efficiency investments through these types of arrangements. Time will tell.

Thursday, August 25, 2016

California Continues to Lead Fight against Climate Change

By Jim Berger, in Los Angeles

The California Senate passed SB32 yesterday, which codifies an executive order Gov. Brown issued on April 29, 2015 establishing the most ambitious greenhouse gas reduction target in North America.  The legislation is intended to make it more difficult for Gov. Brown’s successor to back off of his aggressive emission reduction goals.

The bill passed one day after the California Assembly passed it. Gov. Jerry Brown has said he will sign it.

The fate of SB32 is ultimately tied to another bill, AB197, which calls for greater legislative oversight of the California Air Resources Board, the entity which implements much of California’s climate policy. Both bills must pass or neither will take effect. However, AB197 was approved by the Assembly on Wednesday, and Gov. Brown said he will also sign AB197, ensuring that SB32 will also become effective.

SB32 extends California’s existing climate change law by 10 years to 2030. It also sets a new goal of reducing greenhouse-gas emissions 40% below 1990 levels by 2030. The legislation builds off of AB32, which was passed in 2006 and called for California to reduce greenhouse gases to 1990 levels by 2020. The original goal in the 2006 law was an approximately 15% reduction to a “business as usual” scenario. California is currently expected to reach the original 2020 target, which is 431 million metric tons of carbon dioxide equivalent, on time. The new 40% reduction target will limit emissions to 258.6 million metric tons of carbon dioxide equivalent per year.

The passage of SB32 is a victory for Gov. Brown. Last year, a similar bill failed after Gov. Brown sought to include provisions that would have cut petroleum use in half by 2030. Despite that bill’s failure, California did pass legislation that required a 50% energy efficiency increase for existing California buildings and a mandate that half of California’s electricity be generated by renewable resources, both by 2030.

One specific requirement of the 2006 law was the preparation of a “scoping plan” for achieving the maximum technologically feasible and cost-effective greenhouse gas emission reductions by 2020. The plan, which sets forth California’s strategy for meeting the emission reduction goals, is required to be updated at least once every five years. The scoping plan is currently being updated to address the Governor’s April 2015 executive order calling for 40% reductions by 2030. The update will now presumably address the newly enacted law instead of the executive order.

Some of the programs that are intended to implement AB32 and reduce greenhouse gas emissions include the Low Carbon Fuel Standard Program, the Advanced Clean Cars Program,  the Short-Lived Climate Pollutant Strategy and a cap and trade program.

The cap and trade program, which the latest update to the scoping plan calls a “vital component” in achieving emissions goals, is currently being challenged in the courts by the California Chamber of Commerce.  The Chamber of Commerce is arguing that it is a tax that should have been approved by a two-thirds vote (it only passed with a majority vote). The litigation has caused significant uncertainty around the program, leading to decreased participation and disappointing results. Earlier this week, it was announced that the latest auction again fell short of expectations with only 32% of allowances being sold, raising only about $8,000,000 for the state.

The California Air Resources Board’s website indicates that the reductions in emissions will come from “virtually all sectors of the economy” and be achieved through a combination of “policies, planning, direct regulations, market approaches, incentives and voluntary efforts”. SB32 should give additional certainty to businesses and regulators as they plan beyond 2020.