Editor: You are Practice Group Leader of King & Spalding’s Global Transactions (GT) Group. What areas of energy and natural resources does this group include?
Culotta: Most of us started out as oil and gas or power lawyers, which remain core practices, though at this point we’re probably best known internationally for our liquefied natural gas, or LNG, practice. At any given time, we’re active on at least a half-dozen major projects in this industry segment. But we are spread across a broad range of projects. While we are weighted toward oil and gas, particularly LNG, we have a very deep practice in international power projects, including district cooling, and are handling some innovative renewable energy projects. We also work on mining projects.
While K&S has a large energy transactions capability in traditional areas like M&A and finance, our core transactional energy focus in GT is our projects practice. We help clients to plan and execute projects that produce, process, transport, store or otherwise bring energy to the world. To put it in cartoon imagery, we work with client teams that combine a patch of dirt, a bag of money, a business proposition and an astounding amount of human capital that all work together to emerge with an operating, profitable oil and gas project, power plant, district cooling plant, pipeline, processing plant, storage facility, petrochem facility or LNG facility.
Editor: What practice areas are involved? What skill sets are involved? I assume you draw upon lawyers from several practice groups.
Culotta: Absolutely, there is a broad range of skills required to represent clients in these projects. And all of us have a fairly good range of required skills. As I said, our core skills are in oil and gas and power, with a heavy emphasis on joint ventures and commercial agreements. But the magic of being in a firm like ours is that we can also draw on the specialized skills of colleagues. Let’s say we are representing a sponsor in developing a U.S. interstate salt cavern natural gas storage facility, one of our specialties. First, we typically help undertake site acquisition, involving our real estate practice. Peter Oxman has specialized expertise in sub-soil mineral rights, and he can help us through the thornier issues. Then, with feasibility studies and engineering contracts, Scott Greer leads a practice within GT that specializes in all matters related to construction. Interstate gas storage projects require Federal Energy Regulatory Commission (FERC) authorization, and for that I would turn to Jim Bowe in our DC office for his considerable skills practicing before the FERC. While the project is undergoing permitting, I’d be negotiating commercial contracts with customers whose use of the facility will produce the steady revenue stream required to finance the project. A large part of my practice is the commercial contracts. And if the project is to be financed, we’ll work with our project finance team – lawyers like partner Todd Holleman – to shape that aspect of the project and negotiate the financing agreements.
Not all these lawyers are involved at all times, of course. We typically work with a small core team and draw on expertise as needed. Some clients will want only a part of the suite of services and will prefer to handle other matters in-house. The lead K&S lawyer’s job is, among other things, to handle core tasks, ensure our service is closely coordinated with the client’s team and ensure the timely and efficient application of different expertise. We follow much the same method in projects everywhere. In international projects, there is an extra dimension in tax and dispute resolution planning. And of course we work with local counsel worldwide to ensure our work conforms to all applicable laws.
There is one skill set that sets the projects lawyer apart from most others: to be successful we must know enough about our clients’ businesses – how their facility is built, how it will work, how they make money, the regulatory and market factors affecting their success, and the state of the market in which they work - so that we can advise effectively about a multitude of issues that go beyond “legal.” This is particularly important in industry segments like LNG. If you don’t understand how this industry works, you take a reputational risk even accepting engagements.
Editor: Are these revenue contracts “take-or-pay” contracts?
Culotta: Yes, take-or-pay is still used in some commodity sales contracts. A good example is the traditional LNG sale and purchase agreement. Most of the gas used to produce LNG around the world is stranded gas, and a cargo not loaded may have no market, or only a distressed market, available to it. In such cases, take-or-pay makes sense. In truly liquid markets like the U.S. gas market, take-or-pay has been replaced by the NAESB form contract, which provides for the customer to either pay or be paid if it does not take a contracted quantity, depending on the clearing price for gas in effect at the time it was obligated to take delivery. And where project finance is available, take-or-pay is often too blunt an instrument. For instance, many projects, like pipelines, power plants and storage facilities, are structured as service providers; they transport commodity, or process fuel into electricity, or act as warehouses for a fee. This fee-based service model reduces the project’s exposure to commodity price risk and enhances its appeal to project lenders. So sponsors in such projects often bifurcate the revenue streams, for instance setting up an LNG liquefaction facility as a tolling facility in a separate corporate structure, and selling LNG through a different structure. While the tolling contracts for these facilities are “firm,” they typically do not require the customer to use the facility at all. Instead, the customer pays a monthly reservation charge that covers the facility’s fixed costs and an acceptable return, and if the customer uses the facility, he also pays an adder for incremental costs of operation. But there are many variations on the theme, often unique to a particular kind of project. We try to stay up to date on all those trends relevant to our practices.
Editor: One of the large projects you discussed in our 2012 interview was the Anadarko LNG project in Mozambique. How has this project progressed?
Culotta: That project is going very well for our client. They have found a lot of gas, and they are actively working with their counterparts in other offshore blocks to fashion a structure for a large-scale LNG export and gas supply project that can handle both existing and future production in Mozambique. LNG projects take a long time to complete because they are so complex. Not only do you have the immense risk and expense of finding the gas – you literally have to sell the LNG before you can produce it. Because an LNG export facility costs so much, sponsors will not undertake that expense unless the output is pre-sold. That market requires time to develop, and the sales contracts are big commitments that take time to negotiate. Likewise, multiple stakeholders are involved, not just the producers, but producers from different blocks with different visions for the project: a government partner that has no prior experience with mega-projects, communities, lenders, large EPC contractors. Pulling all this together is a staggering task that will not happen overnight, but they’re making steady progress.
Editor: What is the regulatory outlook for LNG projects in the United States? Are there any environmental risks?
Culotta: In my view, none of the LNG facilities presents a particularly high environmental risk. The Sierra Club has repeatedly raised that issue in proceedings before DOE and FERC, most vigorously with respect to their approvals related to the Sabine Pass liquefaction facility. They argued that allowing LNG exports would encourage fracking because shale gas would be needed to supply those export terminals. Since fracking is a known “evil,” they reasoned, it was therefore wrong for DOE to approve the export permit and wrong for FERC to approve the additional construction at Sabine Pass, even though it would be built in the footprint of the original plan. In a well-reasoned decision, the FERC rejected those arguments, deciding that the sources of supply are so numerous that it is impossible to say what sources are supplying the LNG to the Sabine facility, or whether shale developments would have been necessary to supply it.
The more interesting issues around LNG exports have been policy issues, namely this: is it a good idea to allow gas to be exported? And if so, how much export should be allowed? We are experiencing lower gas prices than we have seen in years. Domestic industries that use gas for fuel or feedstock are taking note, and we may be on the brink of an industrial renaissance. The executives from these industries have not forgotten that only a half-dozen years ago the price of gas was three times what it is today. Many are lobbying for restrictions on export. On the other hand, the price of gas is currently so low that many producers are losing money. They are crying out for anything that puts a floor under the gas price. The DOE – up till now – has been steadily granting permits.
Editor: What other large projects are being undertaken by the Global Transaction Group?
Culotta: As I mentioned, we are probably best known for our LNG work, and we are active on projects from Papua New Guinea to Cyprus. But we have expanded our group over the last year to add some very talented lawyers in a couple of other important areas. One is a team led by partner Kelly Malone. They are international power development specialists located in our Singapore and London offices. Their core business is power projects in developing countries, particularly hydroelectric projects. They are working in Peru, Indonesia, Malaysia, Uganda, Turkey, and the Republic of Georgia, among other places. They represent project sponsors and capital providers for these projects. Working with other lawyers in the firm and local counsel, they secure the site for the project; work with governments to get the concessions or other authorizations to do the project; and handle power purchase, engineering and construction, and other agreements, interacting on a regular basis with various national and multilateral agencies that specialize in underwriting these projects. The principles are the same as for the oil and gas side of our practice, but the practice requires very specific skills and experience with power generation.
We also just brought in a group in Paris led by Mehdi Haroun. Mehdi is both an Algerian and a French lawyer, with skills in both power and oil and gas. There are six lawyers in his group, and their specialty is regional, with a strong reputation in France, North Africa and Francophone Africa generally. Among other matters, they are working on France’s first and largest offshore wind farm projects for our Danish client DONG Energy, and on a gas-to-power project in Mauritania for our client Tullow. The group is composed of Arabic as well as French and English speakers, and has given the firm a capability to extend our geographic coverage into some pretty important new markets in Africa.
Editor: What is the likelihood that the Keystone XL Pipeline will finally win U.S. governmental approval?
Culotta: I represented Shell as an anchor customer a number of years ago in securing transport capacity on the Keystone XL. We all knew at the time that it would be a controversial project because it carried heavy crude, but no one knew what a pivotal political issue it would present. It has truly been an offering to the President’s political base. In fact, the southern section of the pipeline that avoids the core controversy area around the Ogallala Aquifer has been approved and is now being built. That is much needed, because in the meantime there is so much North American oil production that the Cushing, Oklahoma terminal is overloaded, bottlenecking production and actually keeping U.S. oil prices artificially high. And there now is so much crude coming out of North Dakota by rail that one has to ask whether there is going to be a continued need for the northern section to bring oil sands crude. I think there is, because oil sands crude is suitable for many refineries on the Gulf Coast that are not able to refine the lighter, sweeter crude coming from the Bakken. So, without oil sands crude coming in through the Keystone XL, we are not maximizing our refining infrastructure. We are also taking significant risk with our relationship with our neighbors in Canada. Keystone was a good idea, tying us together with Canada in a beneficial way. Now Canadian producers and their government are being forced to look to other customers in other countries, and a chance to forge another good, strong infrastructure and geopolitical tie with Canada could possibly be lost.
Editor: In which areas of the world are you currently seeing the greatest amount of hydrocarbon extraction today? What conditions operate that encourage this activity?
Culotta: The greatest amount of extraction is right here in the U.S. There is a tremendous amount of hydrocarbon extraction going on, to the point where we have reduced the price of gas to almost untenably low levels. Almost unbelievably, there are reports that if Syria doesn’t spark a regional conflict, worldwide oil production may start to drive down the price of oil, too. It may sound incredible, but I have seen oil prices dive by multiples twice in my career. And consider this: while there is a world market price for oil, you cannot readily export crude oil from the U.S. The U.S. is predicted to be the world’s largest producer within six or seven years. As we import oil from other countries and as we produce oil that cannot be exported, one can see the possibility of a glut. The driver in the U.S. remains private ownership of mineral rights. Unlike the rest of the world, in the U.S., an individual landowner can derive benefit from exploiting the oil and gas under his land. Oil and gas companies compete for these rights and compete to bring product to the market at the lowest cost. This creates an innovative investment environment.
Russia of course continues to produce tremendous amounts of oil and gas; it has an oil and gas-dependent economy. It remains a huge supplier to Europe, putting Europe in a precarious position as a giant consumer of energy that is trying to figure out ways to avoid such dependence. But it is not necessarily an efficient producer. Because production is basically state-owned, it suffers from some of the same inefficiencies as other government-run oil economies. If oil prices drop, Russia will be in a precarious position. The Middle East continues to be a significant producer, though the North American oil glut may make its current swing production role less relevant, and with the social unrest following the Arab Spring, some of the regional producers represent less than dependable supplies.
We may see more production in Europe soon. France is struggling with the fracking ban, but voices in the government are advocating approval of innovative methods of well stimulation. England’s government (if not its population) is trying to create incentives for shale gas production, and I foresee that going forward there. And, of course, we are seeing a lot more exploration and production in Africa. Our investment in Mehdi’s group attests to the growing importance of Africa as a producing region.
Editor: President Enrique Pena Nieto of Mexico has introduced the possibility that foreign oil companies will be invited into the country to aid in energy extraction. What is the likelihood that he will overcome the opposition to this proposal?
Culotta: Mexico, which has been shut off from the international oil industry for 70-odd years, has two constitutional amendments on the table before Congress: one from the Institutional Revolutionary Party (PRI) and one from the National Action Party (PAN), the previous governing party. Each party is proposing in its own way to liberalize the constitutional restrictions on the government’s contracting with private capital.
Mexico, with the possible exception of North Korea, has the single most-restrictive rules of any country around private participation in its petroleum industry. Its constitution and regulating laws currently prohibit any form of production or profit sharing. It will allow oil companies to charge a fee to provide service. But that is not the international oil industry’s business model. Oil companies want to take risks and get rewards in proportion to the risks. They will not enter a country that does not allow a competitive return proportional to the risk. There is in effect an international market for their capital, energy and expertise, and Mexico simply can’t compete.
Mexico is figuring this out as its production declines, being a net gas, LNG, and gasoline importer by a large margin. It is still an oil exporter, but its reserves are declining ever more rapidly. It only drilled five wells last year in the deep water compared to 35 in the U.S. Gulf. It drilled at most six wells onshore last year compared to 10,000 in the Texas, Louisiana and Oklahoma area. Mexico is not doing anything with its resource and will not accept the industry’s help. There is a stark realization that change must take place, but there is a lot of political resistance. The PAN has strongly maintained that Mexico should do what Colombia and Brazil have done – turn over at least some of the reserves to a concession system – what we call here a licensing system: getting the government out of the business of trying to be the only actor in the industry, and incentivizing international industry and collecting revenues from production instead. While no one thought Colombia had large resources, the country changed to a concession system in 2003, and the lid came off. We are currently working on four oil and gas projects in Colombia. Likewise, Brazil was thought not to have any oil or gas at all until the late ’90s when it went to a concession system and shot thousands of miles of seismic data offshore for use by all comers. Nobody was even interested in Brazil before, and suddenly it is a major producer.
My view is that Mexico could be the next Iraq, but President Pena Nieto of the PRI is in charge of the message and has responded to the sentiments of his party. In his constitutional amendment proposal, he has left the door open for contracts that conform to international industry standards, but his proposal muddies the language and proposes unattractive secondary language, so that the extent of the liberalization is not clear. For instance, the secondary legislation provides for “profit-sharing” contracts, which would require contractors to contract with Pemex and to receive their payment from a national fund where “profit” is divided between the government and the contractor, who is paid in cash. My concern is that the bureaucracy and political risk inherent in this approach will cause the amendment to be received with muted enthusiasm.
The right result for Mexico would be one that allows not just the large oil companies but the smaller ones – the ones that created the shale revolution, and that currently are crowding the Mexican border in Texas’s Eagle Ford fields – to participate. Smaller oil companies are big risk takers, but they do not have the balance sheets to work in an unsettled environment where the biggest risk is political. Colombia’s oilfields were brought to life by just such players.
The drama in Mexico is still unfolding, and we are following it closely. The PRI likely has enough votes to pass this amendment because the PAN bloc is likely to vote for it, and the PRD, the third smaller party, does not have enough votes to block their combined votes. The question is, when does this legislation get passed? Optimists say it will be before the end of the year. We’ll see. One thing is sure: if Mexico gets it right, all other prognostications about the international oil and gas markets will have to be revised.
Editor: What role do you see for private equity in spurring energy production?
Culotta: A large part of our practice involves private equity, particularly in the U.S. midstream market and, to a lesser degree, the upstream market. By midstream I mean those facilities between the wellhead and the end user. The midstream space presents a fair amount of development risk. The U.S. energy capital markets are increasingly selective about the risk profiles of different market players, rewarding those that develop a differentiated business model. For instance, companies that produce a steady revenue stream by charging fees for the use of basic energy infrastructure are favored by the public markets, and the MLP phenomenon has grown partly out of that differentiation. MLPs are not encouraged by the market to take risks like greenfield development risk – failed projects can negatively impact an MLP’s returns, and the market depends on MLPs for very steady distributions. Traditionally the MLPs have had corporate affiliates outside the MLP that can take on these projects. But more often, the thousands of miles of pipes and the many processing and other facilities that those MLPs end up owning are built by private-equity-sponsored teams -- literally, a few talented people, a bag of money, a patch of dirt, a good commercial strategy and an appetite for risk.
Private equity is well suited to this risk profile. While the development risk may be great, the IRRs on success are as well. So private equity funds take on a portfolio of projects, knowing some will go better than others, but seeking to bring overall high IRRs to their investors – in the 25 percent-plus range. Investors have responded with enthusiasm, even through the recent downturn. So private equity has thus become extremely important for bringing midstream projects to market. It has become the “farm club” for the MLPs, providing finished projects to MLPs in competitive auctions and negotiated deals. In recent years it has been just as important in the upstream market, where funds like FirstReserve have made really big commitments. This differentiated participation of private equity in the industry is an expression of how nearly perfectly we have codified our oil and gas infrastructure regulation; dependable rules and a well-developed market have truly increased market efficiencies. There is a great delineation between the economics of the commodity market and the market for transport, storage or other functions; likewise, there is a continuing differentiation of capital sources for different industry risk profiles. You can almost hear the gears click sometimes.