Negotiating corporate PPAs in the Middle East and Africa

Publication | February 15, 2017

Sizable reductions in the cost of solar equipment have created countless opportunities for developers operating in the Middle East and Africa to enter into power purchase agreements with commercial and industrial enterprises and to provide electricity at a lower rate than the local utility.

Solar pricing on government tenders continues to hit record lows, raising questions about long-term market sustainability. This is causing some developers to try to secure deals with corporate offtakers directly.

However, developing a commercial or industrial solar project in any emerging market is challenging. PPA negotiations with C&I offtakers, who often have either limited or no experience in buying electricity, and maybe no project finance experience, can be extremely time consuming.

A group of energy executives actively involved in solar C&I development in the Middle East and Africa talked at a Solarplaza conference on “Unlocking Solar Capital” in Kenya in November about their experiences.

The group was Ira Green, managing partner of GG Energy, Jeremy Crane, CEO and founder of Yellow Door Energy, Raoul Ilahibaks, senior associate, renewable energy, at ResponsAbility, Roberto Martin, business development manager for East Africa at SolarCentury, and Matthew Tilleard, managing partner of Cross Boundary. The moderator is Marc Norman with Chadbourne in Dubai.

MR. NORMAN: Roberto Martin, as a business development executive working for a solar power plant developer, you are in close contact with C&I offtakers. I suspect one of the very first questions they ask you is, “Is solar actually going to work at my factory? I do not know the technology. Can I have confidence that the solar installation will not disrupt our company’s operations, and that the savings on electricity costs will be worthwhile?”

MR. MARTIN: Yes, in the initial stages, these are exactly the questions we get.

Another typical question is, “I see solar working in places like Europe and Latin America, but is it really working in Africa? There is no track record.” Over time as we build a track record, confidence in solar will increase and those questions should be less common.

The next stage is when customers start saying, “The technology is working. I see the numbers. How can you finance the solar system?” That is when we need to think about structuring a financing product. We see an increasing number of financing companies coming into the market, and we are seeing a lot of growth in this segment.

When we start looking into PPA terms, one of the key words for potential customers is “flexibility.” A corporate PPA is a different model. We are not talking to state-owned utilities with tried, tested and bankable PPA models and standardized processes for project procurement. We are talking to a wide array of customers from various sectors, often with very different profiles. So a solution that works for one customer may not work for another. In this context, flexibility is key.

Some customers only look at long-term savings, while others focus on short-term. This affects expectations on the PPA term. Customers that do not trust the technology tend to want very short PPAs — perhaps one, two or five years. The flexibility that we are able to offer is key to making this model work.

MR. NORMAN: If a developer wants to raise financing for these projects, the PPA must be long enough to support the debt. Ideally, you want a PPA with a term of at least 15 years. How do you get around this problem with potential customers who are only willing to commit for one to five years?

MR. CRANE: Commitment is always an issue in every aspect of life. [Laughter] Solar has a long-term payback, depending on the cost of power. In Jordan, where utility prices are high, we had the benefit of being able to generate high returns with a relatively short contract. The flexibility that an offtaker needs varies from one business to another.

For example, what flexibility does a shopping mall need that hopefully will be operating for a couple decades? Maybe the owner will want to add another floor? Then it is flexibility about removing and reinstalling the solar system. If you are dealing with a commercial enterprise, the flexibility could be something like a roof replacement, and that can be dealt with contractually. We will promise to remove the panels and put them back on the roof once over the life of the contract.

In a place like Kenya where electricity prices are fairly low, I cannot see a financed solution — a PPA, a lease, or whatever you call it — that does not require a customer to make a long-term commitment. The cost of the solar project takes time to pay back. The customer has to make a choice: “Do you want to save the maximum dollars in year one, and then take a long commitment, or are you willing to save very little, maybe nothing, and have a shorter-term commitment?”

MR. TILLEARD: People do not have problems with the length of the contract per se, but they have problems with the practical implications. What happens if I move site? What happens if the currency changes by 400%? What happens if the electricity tariff changes? These concerns do not rule out a long-term contract. We have to come up with the contractual structures that address these practical concerns.

We are fully focused on C&I solar. We are building and operating assets in Africa only. We spend all our time thinking about how can we structure these contracts to address these practical concerns.

Opportunities

MR. NORMAN: Ira Green, you deal with private mining companies. Mining operations are sometimes unpredictable. For instance, work in a mine may be suspended when commodity prices fall. This is an issue from a financing perspective. How do you work around such challenges?

MR. GREEN: We focus on mines that have a long life ahead of them. In some cases, the projected remaining life is as long as 35 years. They are some of the deepest and richest mines in terms of mineral ore.

I just want to bring in another point here, because we talked about PPA pricing being important. It is important, but with many C&I customers, particularly in Africa, there are two other big issues. One is power quality. The other is availability and stability. If an offtaker in Africa is connected to the grid, power is often weak. If the customer is at the end of the grid, it will likely have issues with voltage fluctuations.

The integration of a solar photovoltaic system, if structured properly, can alleviate a lot of those issues and provide offtakers with a better quality of power at a competitive price. That is something that is very important for the mining industry. People need to take that into consideration when assessing the terms of these contracts.

MR. NORMAN: Raoul Ilahibaks, ResponsAbility helps developers explore investment opportunities in C&I solar. We often focus on how much customers can save against the price charged by the local utility for electricity, but where there is no grid, solar is often competing against diesel. The potential for C&I solar is likely to vary greatly from country-to-country, and from one site to another. Where do you see the most potential?

MR. ILAHIBAKS: It depends on the state of the local utility, electricity prices, and connectivity.

Take Rwanda, for example. You have a lot of diesel being imported into the country, and many large companies are still using diesel generators as a backup. It makes sense in Rwanda to displace some diesel with solar.

In Tanzania, where electricity prices are highly subsidized and the national utility is weak, solar photovoltaic systems are being offered as an off-grid solution: to mining companies, for example.

It depends on the country, and the reliability of the grid. It also depends on what the customer is really looking for. Is the customer looking for more reliable power or is it focused mainly on the cost?

MR. NORMAN: To what extent are offtakers willing to pay a premium for storage to have stability of electricity supply?

Rwanda is one of those markets where the grid tends to go off several times a day, not necessarily for very long, but between one and two hours a day.

Matt Tilleard, Cross Boundary has just signed a PPA for a fairly big solar C&I project in Rwanda. Was the offtaker on that project interested in storage, notwithstanding the cost? What is the market for storage?

MR. TILLEARD: I think storage is too expensive. Storage is a potential future technology, notwithstanding that we have two solar battery PPAs operating in Kenya. They are for a particular application. They are for remote, off-grid safari lodges where diesel fuel is trucked in across ecologically sensitive land, and people are paying US$1,500 a night for a tent. Customers who pay for this type of camping experience do not want to listen to a diesel generator. [Laughter] In that type of scenario, storage makes sense.

For our Rwanda project, storage does not make sense yet. The Rwanda project is for a large multinational company. The project is small at around 1.5 megawatts, but we will be adding close to 1% of the generating capacity of the whole Rwandan grid.

The nice thing about the PPA model is that when storage does make sense, we will be the first people there, and we will be able to go back to all of our existing customers and add storage to their existing solar systems. Storage will help increase reliability and power quality when the time comes.

Pricing

MR. NORMAN: We have talked about reliability as a selling point. However, the ultimate question is price. Roberto Martin, how much of a discount do you need to show from the local electricity price to have a sale?

MR. MARTIN: For perhaps 95% of customers in Kenya, the key motivation for looking at solar is cost savings.

If I could first, let me add to what was said earlier about battery storage. We are currently installing batteries on one of our solar photovoltaic systems. I agree that it is not economically viable if the goal is to compete with the grid, but it is probably competitive with diesel generators. At SolarCentury, we believe solar plus storage will be economic within fewer than five years. Once we integrate batteries, we will be solving more problems than we are now.

Another challenge we have with corporate offtakers in Africa is the take-or-pay clause in the PPA. They understand the concept, but the problem is how to make it workable from an operational standpoint. Sometimes a business may not operate on the weekend, meaning that there is little-to-no need for electricity during such time. A customer may also have seasonal operations. Without storage, the offtaker will have to pay for electricity that it does not need. That is a big challenge for many businesses. One solution is including batteries. Another solution would be for governments to implement net metering regulations: if an offtaker is permitted to feed excess power to the grid and then take it back when needed, this makes solar much more compelling.

MR. TILLEARD: Returning to pricing, when we first did the model for our fund, we thought we would tell customers you are paying 12 US dollar cents in Kenya for your electricity, which is the price for most large industrial customers, but you are running on diesel 20% of the time, and diesel costs this much, so your weighted average cost of electricity is X. But by that stage, the potential customer is already bored.

Our customers are not really interested in the weighted average cost of the grid versus diesel. It has been very difficult to make the case on this. What we have found is that we generally need to be 20% cheaper than the grid. Until that point, you are just wasting a lot of sales time and effort.

MR. NORMAN: Jeremy Crane, customers ideally want to set a fixed tariff throughout the term of the offtake agreement, but this may not always be workable. To what extent are you managing to build some escalation into your PPA tariffs, and how is it structured?

MR. CRANE: These are very interesting questions. On savings, I agree: 20% is a good number. If you can hit that, customers get interested. If you are talking 10%, is it worth their time? Depending on the size of the customer, you may be talking about US$1,000 a month. An important CEO probably does not worry about such small amounts.

With regards to price escalation, the power industry is in a price compression phase. I am talking globally. In our backyard in Dubai, we are seeing ridiculously low prices coming in for power generation. The cost of power generation will continue to fall during our lifetimes. There will always be a premium paid for grid interconnection, and we will pay that as long as it is less than the cost of batteries.

As soon as batteries become economical, then maybe the grid is no longer relevant to us and our industry. In the meantime, we pay. As a consumer at my house, I pay for the generation that happens a long way away, and I pay for the transmission to my house. If I was to price to a consumer today at, say, 20% off 12 US dollar cents a kilowatt hour and I was to put an escalator in there, expecting the customer to follow inflation, I am going to be moving that customer out of the market of economic benefit as I move forward, and that will put my contract with that customer at risk. So I do not think that is a viable scenario. In fact, in many situations, we price relative to the grid. In case grid prices go up or down, we will follow the grid pricing.

MR. NORMAN: Raoul Ilahibaks, another price-related issue that worries offtakers in the Middle East and Africa is currency risk. If an offtaker is being asked to sign up to, say, a US dollar tariff payable in a non-pegged local currency, then its key concern is a scenario where the local currency plunges against the US dollar thereby increasing its solar energy charges to a level that may be no longer viable.

Some of the offtakers you and your clients deal with are local enterprises. They will be getting their revenues in local currency, and so they will want to deal exclusively in local currency. When you are dealing with big multinational companies, perhaps mining companies, they may be getting some of their revenues in US dollars and will be happy to pay you in US dollars. Do you have any thoughts on currency-related issues that one typically encounters in these deals?

MR. ILAHIBAKS: Offtakers can be separated into three different buckets: the big multinationals, the local companies that have hard currency revenues, and the local companies that only have local currency revenues.

The multinationals are part of a larger organization and can absorb currency risk. For these companies, agreeing to a hard currency-denominated tariff is less likely to be an issue.

But if you look at the other two buckets, currency is a big issue. And this is problematic because that is where the majority of the market is. In order to unlock the potential of these two buckets, we need to find a solution to the currency issue.

We are looking at local currency lending. We need more participation from local lenders in the market, whether from local banks or entities like GuarantCo, to provide local debt financing.

The low-hanging fruit is the multinationals, but to capture the bigger part of the C&I market, we need to find a solution for currency risk. I believe institutions like TCX can help with these currency issues, but local banks need also to play an active role.

MR. GREEN: I agree. There is another complexity that affects all three of your buckets and that is the regulatory framework for payments.

In certain countries you cannot be paid in foreign currency. For example, if you have a project in Tanzania, you are not permitted to be paid in any currency other than Tanzanian shillings. So you would have to seek a currency hedge — which the local banks or your lender can provide — but that adds to the cost.

Off balance sheet

MR. NORMAN: There is another big topic: deconsolidation.

Often when you start off negotiations with corporate offtakers, one of the first things that an offtaker will tell a developer is: “We do not want this project to be on balance sheet. That is why we are coming to you. Otherwise, we would have done the project ourselves, or procured it on an EPC basis. We therefore want you, the developer-financier, to do the project for us, and structure things so that the project is not required to be consolidated on our books.”

We spend a lot of time as lawyers working with developers and their accountants to structure the contractual arrangements so that they are off balance sheet.

Devising these type of structures can be challenging because deconsolidation requirements can sometimes be inconsistent with typical contractual structures and terms. Also, the accounting rules are constantly evolving.

Consider the following example. A developer is dealing with a potential offtaker that will not do a deal unless the project is off its books. Assume the potential offtaker is accounting under full International Financial Reporting Standards. The developer has typically structured its offtake agreement with corporate offtakers as an operating lease, rather than an on-balance sheet finance lease, to avoid consolidation. Depending on how the developer’s operating lease is structured, it may soon be impossible for the developer to offer an operating lease to this type of offtaker.

From January 2019, IFRS 16 will require all leases, with limited exceptions, with a term of more than 12 months to be brought onto the lessee’s — in this case, the offtaker’s — balance sheet. This includes operating leases. IFRS 16 defines a lease as a contract, or part of a contract, that gives a lessee the right to use an asset for a period of time in exchange for compensation. Determining whether an arrangement is a lease hinges on whether a lessee controls the use of the asset. The focus is on whether the lessee has substantially all of the economic benefits from use of the asset, and whether it directs the use of the asset throughout the period of use. In each case, assessing control is a matter of fact based on an analysis of the particular contractual arrangements. So an operating lease model may or may not be viable, depending on whether the contractual terms grant control to the offtaker.

If, for whatever reasons, neither a PPA nor a lease is viable, then the developer should consider alternative offtake structures. We are working with developers on energy savings contract models, where the developer effectively acts as a service company.

I know that for some offtakers, deconsolidation is a really important issue, and that any risk of the project being consolidated on its balance sheet is a non-starter. Ira Green, what has been your experience?

MR. GREEN: It is the biggest stumbling block that we face in the C&I space. You have to figure out a bespoke solution for each customer.

Regulatory constraints also heavily affect structuring. In some cases, you may want to structure a joint venture with the offtaker so that the project is considered a self-generation project. If you operate in a market where the state utility is the single buyer and distributor of electricity then, as a pure independent power producer, you will likely run into issues. If you create a joint venture-type structure, you can avoid some complications.

That is one solution. Otherwise, I am beginning to hear that there are potential funders, development finance institutions and the like, that might be willing to help and take some degree of balance-sheet risk. They have sufficient resources to do that in order to facilitate the deals. That is another potential avenue.

MR. NORMAN: Matt Tilleard, I think I have a flavor already of your views. To summarize quickly: when you first started off, you realized that deconsolidation was an issue and you, like us lawyers, had a very big think about structuring. But you then came to the conclusion that too much reflection was perhaps leading to over-complication.

MR. TILLEARD: We have spent a lot of time in conference rooms trying to design the perfect product that would solve the deconsolidation issue and, honestly, customers have never brought it up with us. Not once. And we are dealing with sophisticated, large customers.

We do have structures in our back pocket that, under Kenyan law, Ghanaian law or Rwandan law — the countries where we already operate — would address these constraints. But for now consolidation has not been a problem; and the tradeoff is simplicity.

Deconsolidation is an interesting point as a financier. We are already trying to convince people to do something that they have never done before. No one in Africa ever got fired for sticking with the grid and diesel. Now they are going to go do something entirely different. They are going to add solar into their energy mix.

When you give a potential customer five options, you say, “We can do it this way, or that way. We can toggle this or that,” the thing they choose is to do nothing. So what we have found works best is to say simply: “This is the deal. It is a simple PPA. You just buy power from us. We take the risk.”

MR. GREEN: The size of opportunities and projects may be a factor. When you are dealing with projects that are sub-10 megawatts, then you may have less of an issue. It becomes a big issue when you are dealing with a project that is 20, 30, or even 50 megawatts.

MR. TILLEARD: That’s fair.

MR. CRANE: We have actually seen deconsolidation come up on small deals too: one megawatt, two megawatts.

Like Matt Tilleard said, you need to adapt to your customer’s needs. With now 30 megawatts of customers under our belt, we have seen a lot of different requests, and what is important is the flexibility to be able to provide a solution that meets the customer’s needs.

You need to hear them. You need to respond to them. But at the same time, you need standardization. So it is a bit of a double-edged sword. But we certainly, with the support of Chadbourne, have found solutions in a multitude of different scenarios. It just takes time.

Other structuring issues

MR. NORMAN: We have touched upon two fundamental, but different, structuring issues. The first is deconsolidation, which certain offtakers require. The second relates to the regulation of electricity markets and the so-called single buyer model.

In a number of electricity markets, the local or national utility has a monopoly on the purchase of electricity. Unless there is carve-out regulation for, say, self-generation, net metering or wheeling, a developer cannot structure its offtake agreement as a power purchase agreement because supplying electricity at retail to an end user is illegal. In this context, the first structuring challenge is how to get around the restriction on supplying electricity. While each jurisdiction has its own peculiarities, there are sometimes ways to structure around these restrictions.

The main fallback options are solar leasing agreements and energy savings agreements.

There is another point that I wanted to touch on, and one that often emerges as a contentious issue in negotiations with corporate offtakers: change-in-law risk. If there is suddenly, say, a major increase in a fee or a tax, and this has a material impact on the developer’s costs, then the deal economics have changed. It could also apply to the offtaker. For example, a new tax is introduced that has the effect of materially increasing the offtaker’s monthly energy payments.

In a government-procured independent power project, the state utility will typically protect the developer, to varying degrees, from potential adverse effects of a change in law. This is primarily because the state utility recognizes that by being government-owned, it indirectly has control over a change in law.

Sometimes you will have a risk-sharing arrangement where the developer takes the hit up to a pre-determined amount — like a deductible portion under an insurance policy — with anything above being assumed by the state utility.

Otherwise, a distinction may be drawn between change in law whose effect is of a one-off versus a continuing nature. If the effect is a one-off, then the developer would get a lump-sum payment as compensation. If the effect is continuing then the tariff under the offtake agreement would be adjusted to compensate the developer for the remaining term.

A corporate offtaker may struggle to assume change-in-law risk. This is something that generally leads to heated discussions. Ira Green, is this something that you come across a lot with your offtakers?

MR. GREEN: Yes. What we find is that offtakers generally do not want to take any change-in-law risk. They believe it should be the developer’s risk. We work closely with our insurance consultants who can structure a political risk insurance that will cover this type of change-in-law risk.

MR. TILLEARD: We use political risk insurance, but it really only covers us where due process has not been honored.

If taxes go up over time, or there is some other change in law that disadvantages us, then that is something that we need to resolve. I have not seen great contractual solutions. In the US, it is pretty standard to force both parties to come to the negotiating table and, in theory, the contract parties figure something out. I am interested in hearing about different approaches.

This is the way we currently play things: these are 25- to 35-year assets, and the contracts are typically 15 years long. If a change in law arises and we are forced to the negotiating table, then we would look to extend the contract to preserve economic value.

MR. NORMAN: That seems to be where a number of developers are landing: take a bit of a soft approach and say, if there is a change in law and the economics have materially changed, then the parties will come to a negotiating table and try to put themselves back into the position that they were in when they signed the offtake agreement.

If you put on the hat of a developer or lender that focuses on government-procured IPPs, you may view this arrangement as too uncertain. This is perhaps one of the prime examples where developers and lenders need to shift their minds away from that government-procured stand-alone IPP mentality toward a more flexible, although perhaps less certain, universe.

We were touching upon the issue of deconsolidation. One of the things we did not discuss is payment security. In order for the developer to be able to raise limited recourse debt financing, a government would typically be expected to offer a sovereign guarantee. And so when dealing with corporate offtakers, developers tend to ask for a parent company guarantee. Any guarantee is a contingent liability on the books of the offtaker’s parent. That would contradict deconsolidation objectives. Therefore, C&I offtakers are often not willing to give the type of payment security that project financiers would typically expect, and sometimes may not be willing to provide anything at all.

When you look at the whole picture and compare, on one hand, the government-procured project with a sovereign guarantee and change-in-law protections and, on the other hand, the privately procured project with very limited or no payment security where change in law is left fairly open, you realize that we are talking about very different animals.

The reality is that project risks on C&I projects are often mitigated by aggregating into a wider portfolio. On a stand-alone basis, corporate PPAs present more risk than a state utility PPA. Perhaps this is one of the key reasons why — to the dismay of C&I offtakers — corporate PPAs cannot be priced as low as state utility PPAs, especially those back-stopped by a DFI. Are you developers having any success getting that message across to potential customers?

MR. TILLEARD: It largely comes back to price. When people start quoting really high electricity prices charged by utilities in certain markets, then comparing the prices to tariffs bid on government-procured solar projects, it seem like the C&I market segment is a bonanza: “We can do solar for six cents, but actually the electricity price is twenty-two cents. We are all going to get rich.” [Laughter]

Actually, it is not like that. In certain markets, it may be a little bit, but not a lot. This is because we are talking about very long contracts involving a lot of uncertainty about how things will play out.

You need to provide a significant incentive to a corporate customer to bring it on-board, to do something that it has never done before within its factory operations, for the general manager of the plant to say he is willing to take the risk. There are elements like change in law, or a dramatic change in the local currency, that are very difficult to control.

It works when you can give a very strong value proposition on price, but not where the cost savings are marginal.

Making the sale

MR. CRANE: I think you need to look at what the alternatives are for the customer. You are dealing with an entity that is consuming a lot of power and paying a lot of money. The people that you are talking with understand that solar is going to save them in the long run. They have three options.

The first option is to hire an EPC contractor. This means they pay for the project from their pocket. They can save money. They take 100% of the risk. They are going to take a risk on execution. They are going to take risk on operation. In a new market, an entity that is cash-constrained will have trouble with that option.

The second option is to borrow money from a bank. Maybe they can get some concessionary loans. We see those coming into the market in places like Kenya. In that scenario, the customer still has a full obligation to repay the bank, and so it is on the hook.

In the third scenario, the one we are addressing, we, the developers, are taking on a lot of that risk: the execution, the operation, etc. In exchange, we need to pass on some of the regulatory risk, some of the change-in-law risk. The customer should appreciate that it has zero dollars out of its pocket on day one. In exchange for that, it must take a little bit of regulatory risk. That is a balance that not everyone will accept, but market to market, we see that around 30% to 50% of companies that want to go solar are willing to take on some of those long-term commitment risks.

MR. TILLEARD: Let me add a “scenario zero” that is to keep doing what you are doing: diesel and grid. Do you think these things are going to be the same 25 years on from now? Absolutely not. Making a sale requires convincing the customer that scenario zero is not an equivalent thing. You cannot completely de-risk solar versus the grid, but the grid is not de-risked either.

MR. GREEN: The other thing to bear in mind is that, in many cases, you are not dealing with a single person within a customer. You are dealing with operations, with a finance person, with senior management and, ultimately, with the board.

If you manage to convince three out of the four, that is not enough. You need all four. All these offtaker questions we have been talking about — essentially, “Why should I take on this risk?” — they generally go to the board. The board will say, “We buy currently from the grid. We have quality issues, and we may have future pricing issues, but we do not have any long-term commitments. So why should we jeopardize ourselves?” The type of arguments that Jeremy and Matt just made have to make their way to the senior management level, even though the operations and finance people see the merits of the project.

MR. NORMAN: Raoul Ilahbaks, I want to bring you in now because one of the things I initially thought we would address during this panel discussion is how to unlock capital for the C&I segment.

You and I discussed this previously. Interestingly, you do not think that there is a lack of capital in the market. You think that it may even be slightly too crowded.

Please comment on that. Secondly, maybe you can tell us what you think is needed for the C&I market truly to take off.

MR. ILAHIBAKS: Two perspectives. On the equity side, I think there is too much capital trying to find a home. I do not think there are any constraints in terms of equity financing.

If you look at debt financing, there are basically two options for smaller projects. Either you go to DFIs, who are willing to look at a portfolio approach. They want to see a pipeline of projects and will give a long-term commitment for a certain amount. In some countries in southern Africa, we have seen a number of DFIs give a US$20 to US$30 million commitment for a portfolio. But DFIs will generally not touch a single project or even several small-scale projects. There is not enough scale.

With smaller projects, the offtakers can go to local banks. But local banks do not typically have the required expertise, and this is a fundamental issue. The offtaker may then look for corporate-level debt. However, this can be burdensome for the offtaker and will eat into its ability to raise debt finance for its core business. Debt financing for projects in Africa really is a fundamental issue to address.

Regarding the length of the offtake agreement, I see things slightly differently than some of the other panelists. The contract term is a major challenge. In Africa, people really do not think on a 15- to 20-year horizon. This has implications in terms of raising adequate financing.


Originally prepared by Chadbourne & Parke. Chadbourne & Parke combined with Norton Rose Fulbright US LLP on June 30, 2017 and is now known as Norton Rose Fulbright US LLP.

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