Independent exploration and production (E&P) operators in the United States have faced a funding dilemma since they began rushing into unconventionals. With more resources than capital, many have taken loans that have increased their debt, or they've sought out joint venture (JV) partners to pay for drilling expenses.
The bank loans have sometimes gone sour, and the JV agreements tend only to provide capital for specific carrying periods. More often lately, independents have begun turning to the "middle," the big private equity lenders, which want working interests in projects instead of only providing loans, according to Kohlberg Kravis Roberts & Co. (KKR) Managing Director Claire Farley.
The KKR executive talked about the ways private equity funds are changing the landscape in both the onshore and offshore last week at the annual Deloitte Oil & Gas Conference in Houston.
Farley said she used to make speeches about peak oil, "not that the resource didn't exist but of the deliverability problem at a certain margin. We've solved deliverability, but in our industry, at least in the United States, so much [of the growth in reserves] was driven by the major independents in the early days and really, they needed a lot of capital required to do all of this.
"Their balance sheets...weren't structured to do this." In addition, they also entered into lease terms with landowners that were not "fitting the kind of delineation, commercialization and development phase that you would like to do in a more measured, focused-on-returns way."
Many landowners want three-year terms, she said, which led exploration and production (E&P) companies to "outspend cash flow...The market continues to reward for growth, not necessarily profitable growth, but in the belief that someday it will be profitable growth."
The amount of cash needed to ply onshore developments and deepwater plays is huge, said Farley. For instance, U.S. independents outspend cash flow 30-40% as a group when they buy and begin to acquire land in unconventional plays, she said. "What they typically do is they go to the debt market to finance...beyond their proved reserves. They are limited by cash flow projections" and equity holders don't want any more equity issued.
"So there's this place in the middle where they go to look for capital, and for several years that's been JV capital" from private equities. It's the middle ground that works well, said Farley. The E&Ps are "actually selling some working interest in those plays, so it's treated as a 'sale,' but they get...the leveraged dollars and that joint venture money..."
Just last week, privately held explorer LLOG Exploration Co. LLC formed a long-term partnership with private equity giant Blackstone to accelerate the E&P's deepwater operations in the Gulf of Mexico (see related story). The partners, which have committed to invest more than $1.2 billion in the alliance, plan to leverage the operational and financial resources of LLOG and private equity funds managed by Blackstone.
End-users also are eying JVs with producers because they can see the advantage of owning resources for the long-term. For example, Farley noted that Nucor Corp., a U.S. steelmaker, did that by taking a half-interest earlier this month in some of Encana Corp.'s natural gas wells (see NGI, Nov. 12). The purchase allows Nucor to guard against an expected increase in domestic gas prices.
"It's the perfect hedge, if you will," she said. "If you have the capital to buy gas at cost, then if prices remain low then you have a low-cost source of supply. If prices go up, you have gains on the capital investment...We've seen some of the utilities do the same sort of thing."
In the past, private equity funds usually set up a fund for several natural gas projects priced at $1-3 billion in size. The funds provided one E&P $50-150 million to finance a particular project. However, that kind of financing soon dried up in the unconventional and deepwater deals. The E&P management teams "would look up and say, 'we need to fund with $300 million, because we're in three plays to gather enough acreage...Wells cost $10 million apiece.' $3 million doesn't go that far today."
That left the door open for private equity, to buy working interests, not just provide capital. For "very large private equity groups," like KKR, Blackstone, Riverstone Holdings LLC and Apollo Global Management, it's proved to be a win-win. Last week Blackstone formed a partnership with LLOG Exploration Co. LLC to accelerate the producer's deepwater operations in the Gulf of Mexico (see related story).
The private equity funds provide E&Ps with money, and in turn they get to take a bigger interest in the play, or the company. With a working interest in a particular play, the private equity gains more oversight and may "take a seat on the board, or take the assets and drop them into a subsidiary...The way KKR is doing it, we're saying that we really should deploy at the asset level, just like an asset partner [JV] would. We can hold that working interest..."
The new types of deals have required private equities to employ geoscientists and petroleum engineers Farley said. That expertise provides more leverage, which to date has led to five different Eagle Ford Shale projects, she said..
"We are looking all over North America to be a nonoperating partner. We believe we will get returns in the mid-teens, and we think that's perfectly good for the kind of risk we're taking. We're providing the drilling capital that debt markets [usually] can do. That's just one innovation, but we're seeing a lot more."
E&Ps need to spend an estimated $60-80 billion a year on capital projects, and not all of it can come from cash flow. "Easily $10 billion to as much as $30 billion comes from some place other than a company's cash flow...So we see very, very significant changes about who invests and how those investments get done. We're just in the early stages of it now."
Buying into an E&P asset requires a patient investor, said the KKR executive. "If you own the assets over 10-20 years, when new technology emerges or when prices go up, they will own all of that asset and pay nothing more for it."
In the midstream arena, $200 billion or so "needs to be invested over the next 20 years for 35,000 miles of new gas pipelines, 500-600 Bcf of new storage," she said. E&Ps "can't afford to do this because they are just having a hard time funding their E&P aspirations." Her firm "tends to take projects in the midstream when the commitment is very well understood...so there's that place in the middle, we used to call the 'mezzanine space.' But it's not a loan anymore. We are owning the assets."
Master limited partnerships (MLP) will be the "largest financier of midstream opportunities," she said. "Some of it will be private MLPs before they are dropped into public MLPs. All have the same notion that investing in something that can give a current yield...The question we worry about is as people rush to this pretty frothy MLP market to take advantage of this phenomenon, such as refineries, [hydraulic fracturing] sands, these are things that we know will clearly not be a way to think about delivering a stable, predictable level of cash flow. Those can tarnish a sector...Just about everybody is talking about MLPs."
The equity markets are seeing "major transformations taking place now," she said. It has led to investors thinking about investments over a longer time frame for returns. "Big pension funds want to own oil and gas at the asset level and own it forever. It's causing us to consider how we go about it.
"You have classic equity with an exit in a 10-year time frame, but this real asset class is in the world where people are hungry for yield. We know that oil, and at some point natural gas, will be perfect for an inflation hedge, but in order to get that, you have to actually own the asset. They say, 'I can't get it in futures,' but they are buying a lot of U.S. independents," which can "suffer tremendous reinvestment risk...We've seen a few ugly cases of that."
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