Author: Stella Farrington
Source: Energy Risk | 30 Jul 2015
As energy companies face a tough time gaining access to capital, a growing number of them have found relief from infrastructure funds and other investors keen to snap up low-risk, low-yielding assets. Three such investors outline their approach.
Meeting global energy needs requires a colossal amount of capital – and the price tag keeps growing every year. In 2014, it cost over $1.6 trillion to supply the world’s consumers with energy, a figure that has doubled since 2000, the Paris-based International Energy Agency said in a report last year.
Unfortunately, gaining access to capital has become a difficult task for the energy industry in the present financial and economic climate. Banking regulation in the wake of the 2008 financial crisis – particularly capital adequacy requirements – has made banks much more cautious about lending. The trend towards loans with shorter maturities has introduced a higher element of risk for energy projects, which are almost always long-term in nature. Meanwhile, structural change in the utility sector has worsened the investment picture. German gas and power giant E.on posted a record annual loss of €3.2 billion (US$3.2 billion) for 2014, hit by weak demand and renewables production eating into market share, and many utilities face similar woes.
Such conditions have led many larger energy firms to divest low-yielding assets. As a result, the past few years has seen a slew of assets come to market – assets that offer lower returns than those sought by traditional investors in the energy sector, such as commodity trading houses or private equity firms, market participants say. For instance, while a typical utility may target annual returns in the low double digits and divest assets delivering below that level, private equity firms would want returns of at least 15%, say investors familiar with the industry.
That has created an opening for a new breed of investors, which previously were not seen as a major source of capital for the energy industry. Such investors – including infrastructure funds and pension funds – seek relatively low yields and long-term, stable revenues. With interest rates at rock bottom and yields on government bonds struggling to make 2% in many of the world’s developed economies, energy infrastructure has emerged an attractive alternative, often yielding returns of 6% to 9%, investors say.
Larry Kellerman, managing partner of Washington, DC-based investment firm Twenty-First Century Utilities, says interest in energy infrastructure has grown to the point where there is now stiff competition for desirable assets. “Currently there is so much capital seeking to be deployed that the good, solid investments are definitely attracting very high-premium returns relative to where they had been clearing even just a couple of years ago,” he says.
Risk management is a crucial piece of the puzzle in making such investments. Infrastructure funds vary in their risk appetite. At the conservative end of the spectrum are ‘buy-and-hold’ firms that seek low but predictable yields, investing in projects where most or all of the risk has been laid off to others – for instance, a wind farm with a 20-year power purchase agreement (PPA) or a transmission line operating under a contract with little variability in its return. At the other extreme, more aggressive funds are ready to take on higher levels of risk, or have more control over the asset, in exchange for higher returns.
Those are the exceptions, though, and most funds seek assets that have been de-risked in some way. “I think the issue now has become the ability to carve the value chain in such a way that you can give an asset the attributes that the low-risk, low-yield seeking funds are looking for,” says Andy Brogan, London-based global oil and gas transactions leader at auditing and consulting firm EY. “The challenge is to insulate them not just from commodity price risk, but execution risk, volume risk and maintenance risk.”
Energy Risk spoke to three investment officers at infrastructure investment funds about how they make business decisions, de-risk their investments and build relationships with players in the energy industry.
Andrew Pickering, Infrastructure Capital Group (ICG)
ICG is an Australian infrastructure investment manager with A$1.5 billion (US$1.1 billion) of assets under management. Pickering (pictured above), based in Melbourne, is the firm’s chief investment officer as well as the portfolio manager of its Energy Infrastructure Trust. The trust’s investments include the 320 megawatt (MW) Kwinana combined cycle power station – one of the largest power plants in Western Australia – as well as gas pipelines, wind farms, other gas-fired generation assets and port infrastructure. Its most recent investment, in April of this year, was the Hallett 4 wind farm in South Australia, which took ICG’s renewable generation capacity to 350MW, making it a sizeable player in the Australian renewables market.
Q: What is your investment model?
Andrew Pickering: We look for long-term investments where we can stabilise or improve the revenue stream. We generally prefer to hold assets for the long term rather than sell them back after a certain time. It’s not a turnaround play; it’s generally a cost of capital play.
Our investors’ required rate of return is lower than that of the typical strategic investor in energy – the trade players, utilities and international energy companies. With pension funds getting between 0% and 2% from government bonds right now, they’re happy to get a 6% to 9% return on infrastructure assets as long as they are comfortable with the credit. Our returns are in the range of 8% to 12%.
Q: How do you decide which assets to invest in?
AP: We filter first geographically, then we look at the revenue stream of the asset. We want to ascertain how certain it is, how stable it is, whether it’s regulated, whether there are long-term contracts in place. If the revenue is merchant, or there are no contracts in place, we’d probably cross it off the list quite quickly.
If there are contracts then we’d look at the cost structure, revenue and the risks around those. For energy infrastructure assets, pure operating costs may be modest but financing and fuel costs may be significant and subject to change. For example, because banks in Australia are less willing to give long-term loans these days, the project could face debt refinancing every few years. Also, input fuel costs could rise. On the revenue side, there’s demand and price risk to consider as well. And if, for example, power prices are fixed, but gas prices rise, you are left with a real exposure to gas prices unless you are lucky enough to have cost pass-through.
Once you have two or three inputs based on assumptions about future prices, the combination could be sufficiently volatile to produce a really bad outcome. We’ve certainly had one project that suffered from a dislocation of prices. It was a biofuel project we invested in in 2005, and feedstock – which was tallow – and off-take prices became completely uncorrelated. The biodiesel was being sold at a fixed discount to the market price, which remained stable, but tallow prices doubled during the early years of operation, far exceeding historical levels. It wasn’t expected and wasn’t a scenario we had modelled. We certainly learnt a lot from that one. The project is still operational, but we sold it a few years ago to a strategic investor. Today we’d be very reluctant to make long-term assumptions based solely on historical market prices, and we’d be even more reluctant to do that for more than one input.
Q: How do you stabilise or improve the revenue stream?
AP: Usually by putting longer-term arrangements in place around financing, costs or revenue. For example, we would rather do long-term fixed-price debt than refinance every few years and hope interest rates will not shoot up. We’ve done a lot of projects with 15- to 20-year fixed-revenue contracts but with only five-year bank loans because that’s all that’s available in Australia. To improve that, we’ve been offshore recently and have borrowed money in the US private placement market and from US insurance companies, and now we have 10- and 12-year debt on two of our wind farms.
In terms of input fuel costs, in certain assets we have the ability to trade around some of our gas contracts if actual usage veers away from what’s been contracted. For example, we own a base load combined cycle generator in Western Australia called Kwinana Power Station. ICG bought a 50% share in Kwinana in 2010 from [Australian natural gas and electricity firm] ERM Power, with the other partner – [Japanese trading firm] Sumitomo – retaining a 50% share and commencing as the operator after ERM’s exit. [Australian energy retailer] Synergy has a 25-year off-take agreement, which covers 97% of capacity. Additionally, we secured a long-term gas supply contract, so we essentially had our key cost and revenue risks managed.
On the face of it, it looks very stable, but we have to constantly work in both the gas and electricity markets to buy and sell both products to keep the revenue steady. Synergy pays a fixed price to use the facility but can run it as little or as much as it needs to. Therefore its gas usage will alter, meaning we may have to sell surplus gas at certain times or buy in the market at other times to top up our contract. We can also run the plant and sell the electricity – it’s just a question of what would be more profitable.
Q: How do you see infrastructure funds impacting the energy market?
AP: Because pension funds are willing to take a lower return on capital, it has enabled utilities to offload assets they don’t want and invest in other things, particularly in renewables. Developers will often get [a project] off the ground and then move it on to infrastructure funds. In Australia there’s more power generation capacity than is needed, so if someone else can take it off the developer’s hands for a good price, that’s appealing and may help repair the balance sheet.
Q: Is there anything energy firms could do better when selling assets to investors?
AP: I don’t think sellers always appreciate the benefit in dollar terms they could bring to their sale if they run the sales process well. One of our criteria for looking at projects seriously is whether the seller has invested in the process and prepared all the necessary reports and materials for the buyer. This can be expensive, but that way they will attract as many buyers as possible.
Todd Bright, Partners Group
Switzerland-based Partners Group has over €42 billion ($47 billion) in assets under management placed in private equity, private debt and direct investments in real estate and infrastructure around the world. Its clients are institutional investors such as pension funds, insurers and sovereign wealth funds seeking exposure to private markets. It has put €734 million (US$807 million) in a dozen direct investments in energy infrastructure, 11 of which have been made since 2010. These include wind farms in Australia, France and Thailand, solar parks in Japan and Italy, a natural gas pipeline operator in Mexico, gas distribution companies in Turkey and Spain, a coal export terminal in Australia and two combined cycle gas turbine (CCGT) projects in Texas. Todd Bright (pictured, above), a Houston-based managing director with Partners Group, heads the firm’s Americas private infrastructure team.
Q: What do you look for when deciding whether to invest in an energy asset?
TB: We look first at the asset profile. We don’t focus on fully merchant assets as they hold too much risk for us. For example, we’d have a hard time getting comfortable with most of the quasi-merchant, new-build CCGTs being built in the US at the moment to replace coal retirements, where there’s perhaps a five-year hedge just to support a five-year financing but then a pure market view beyond that for equity returns. At the other end of the spectrum, we’re not likely to compete for fully long-term contracted assets with single digit returns – for example, an operational wind farm with a 20-year PPA in place.
We don’t invest at the development stage or look at novel technologies. We need enough cashflows contracted, or enough revenue predictability, that principal is well protected but there’s still some sort of value creation agenda around the asset.
Q: What might that be?
TB: It might be an asset that has expansion prospects. Partners Group’s acquisition of Mexican gas pipeline operator Fermaca is an example of this. Partners Group became a majority stakeholder and sole equity provider in Fermaca on behalf of its clients in February 2014, in a transaction that valued the firm at $750 million. Fermaca already had two fully built pipelines but also had a growth plan to further build out its network of gas pipelines and continue to capitalise on opportunities to bring US shale gas into Mexico. The following May, Partners Group led the refinancing of Fermaca’s existing debt, issuing $550 million in investment-grade bonds. This has allowed Fermaca to secure new projects including tenders for a 262-mile natural gas pipeline within Mexico and a 200-mile pipeline connecting Texas and Mexico.
Another kind of value creation opportunity we look for is investing at the construction phase and de-risking it simply by taking it into the operational stage. For example, in June of this year, Partners Group became the largest shareholder in the 240MW new-build Ararat Wind Farm in Victoria, Australia. The AU$450 million (US$334 million) project was originally developed by UK-based Renewable Energy Systems, which remains a shareholder and operator. Construction on the site has started, with completion scheduled for mid-2017. Once completed, it will be Australia’s third-largest wind farm. In February 2015, the project was awarded a 20-year feed-in tariff by the Australian Capital Territory Government for a significant portion of the wind farm’s total output.
Another major value creation opportunity we look out for is an asset that has a re-contracting opportunity in the future, such as an expiry of an off-take contract. We’re looking at an opportunity now in the US for a power asset that has less than 10 years remaining on its PPA. Beyond that, a new contract can be signed either with the existing off-taker or with new counterparties.
This is a good example of the type of profile we might look for. There is principal protection from existing contracts but upside potential from a re-contracting opportunity. Some infrastructure funds would not be comfortable with the re-contracting risk and this keeps the competition down for us, but at the same time these investments are not as risky as merchant or development-stage assets.
Q: How involved do you get in the day-to-day operation of the asset?
TB: We are an active, hands-on investor, but it’s not our business to manage assets day-to-day ourselves. The day-to-day management is provided by management teams or service providers at the asset level. There’s a big universe of asset management services providers. Potential partners could be a management team or strategic players in the business, such as a utility.
Q: What do you look for in an asset management partner or operator?
TB: We look to partner with management firms that have the necessary industry experience to carry out our value-creation agenda. Ideally they have also worked with private equity-type sponsors in the past so they know how we operate and view the world. But most importantly, there needs to be an alignment between the two parties over issues such as the valuation of the asset and the share of risk and reward to be taken by each party. There are lots of firms with the industry know-how and experience of working with investors like us, but getting alignment is the toughest part. It’s the biggest source of friction in negotiations with management team partners, and we’ve had to walk away from many deals because there wasn’t proper alignment.
Q: What difference do infrastructure funds make to energy markets?
TB: Capital formation for energy projects would be a tougher process without these investors. It’s still not an easy process, but for well-structured projects there’s ample equity and debt capital right now in part due to the presence of financial sponsors and funds in the market. It’s a capital-intensive sector and without sponsors it would be difficult to get projects off the ground.
Larry Kellerman, Twenty-First Century Utilities (TFCU)
Larry Kellerman (pictured, above) has spent much of his career buying, restructuring and selling power plants, notably as head of Goldman Sachs’s Cogentrix unit from 2003 to 2010 and then as chief executive of Quantum Utility Generation, a unit of Houston-based private equity firm Quantum Energy Partners, from 2010 until January of this year. Upon leaving Quantum he started TFCU, which aims to acquire regulated utilities in North America and optimise their commercial models.
Q: Why are you targeting regulated utilities now?
Larry Kellerman: A well-run regulated utility can, in today’s macro environment, economically outperform an independent power producer (IPP) and is much more attractive from a risk-return standpoint. This is a phenomenon that’s only emerged in the past three years or so. It’s what’s attracted infrastructure-type funds as well as the likes of Berkshire Hathaway [the US conglomerate owned by billionaire investor Warren Buffett] to electric utilities. If this space is attractive enough for Warren Buffett to be highly focused on, that’s a statement on the relative attractiveness of a regulated utility.
In today’s marketplace, returns on solid, high-quality regulated utilities – if acquired at the right value propositions and managed effectively – can be very similar to, if not several hundred basis points higher than, the returns that can be garnered in the IPP space, but with less risk. It’s not because the regulated space has improved, but because the IPP space has become a poorer place to deploy capital from a rate-of-return standpoint than it has been probably for the past 20 years. Even a contracted IPP is, at best, a derivative utility credit, as opposed to [a regulated utility with] the benefits of a regulatory safety net and a cost pass-through mechanism.
Q: What sort of assets will you look for?
LK: We are targeting integrated regulated electric utilities, and we would consider individual or bundled regulated generation or transmission and distribution assets. We’ll start looking at what’s out there seriously once we have secured our upsized funding.
Q: Can you describe your optimisation strategy in more detail?
LK: We believe the regulated utility space is an asset class that’s subject to optimisation. There are a lot of new technologies and ways of interfacing with customers that the incumbent utilities are often hesitant to embrace or even, in some cases, afraid of. We see technologies that typically exist on the customer side of the meter – such as smart-grid applications, rooftop and community photovoltaic, customer-facing co-generation [combined heat and power generation], community wind generation, conservation-oriented technology and even battery storage – as potentially very impactful. It’s not just about supplying electrons any more. We believe that offering customers ways to reduce consumption and produce clean, cost-effective power is one of the emerging functions of a modern utility. We are looking at all these technologies because customers are looking at them and are interested in them.
We believe what a utility does best is to provide a secure, reliable product at the lowest possible cost. Most regulated utilities have investment-grade credit ratings thanks to having a workable regulatory scheme, a large capital base and essential monopoly status in their own service areas. This gives them a very low cost of capital in an extremely capital-intensive industry. For example, over 95% of the cost of solar power is capital-related, with operating costs being very low. Utilities’ low cost of capital means they can help drive down the cost that customers would otherwise have to pay for these new technologies. A utility could use its cost-of-capital advantage to own, finance, operate, manage and maintain all rooftop solar panels in its service territory. Customers could select from any pre-qualified vendor, with the utility being able to help bring these important technologies into much wider-scale deployment through enabling customers to take advantage of its financing terms and costs. And all of this would be done on a voluntary basis. By giving customers an additional low-cost and reliable choice, customers will be more likely to adopt the cost-saving and environmentally attractive technologies that are today only being deployed by the wealthiest subset of customers in any utility service territory.
Essentially, we will make money just as a utility makes money today, on earning a fair, regulated rate of return on owning and financing high capital cost items. But instead of building a large nuclear plant, I want us to build 25,000 small photovoltaic installations.
Q: Do you think distributed generation spells the end of the current utility business model?
LK: I don’t subscribe to the death-spiral theory, and I believe that utilities will embrace new technologies and rejuvenate their business models rather than being made obsolete by new technologies. Rather than seeing, for example, rooftop solar as an existential threat, utilities will use their local logistics and cost-of-capital advantage to incorporate this technology into their business model. They need to reach out to customers and offer to be the financier and provider of these technologies.
Over the decades many new technologies have emerged that have affected both power generation and the use of electricity, and utilities have been able to adapt incrementally to include them in their business models over the decades. I have no doubt that this evolutionary, adaptive process will continue in a manner enabling utilities to survive and thrive well into the future.