Mile High Capital

While risk-shy debt markets throw real estate and durable goods markets into disarray, investors and lenders are turning to energy as a solid, defensive strategy. In Denver, that means energy lenders, capital providers and market-makers are making hay while the sun shines on favored sons—independent oil and gas producers.

It’s no surprise that E&P companies and their associated service providers are seen as safe havens for precious capital placement as commodity prices soar with no end in sight.

In reaction to increasing oil and gas prices, lenders’ energy prices decks are rising, even disconnecting from the Nymex strip price altogether in some cases to follow market trends.

Privately owned American National Bank rarely changes its maximum Nymex price forecast, but it did so recently when it increased its price deck to $75 per barrel and $7.50 per million Btu, flat, putting its forecast in the upper third of bank price forecasts.

“Some banks always use the Nymex strip for their prices, but there is more to coming up with a loan value than just the price deck,” says Gary W. Vick, senior vice president and manager of the energy division for American National.

“Our methodology allows us to get to the same loan values as banks that use the strip, but we have the advantage of avoiding large swings in loan values that result from using volatile strip-based price forecasts that fluctuate with the commodities market.”

American National positions itself as a community bank. Its energy division offers $1- to $50-million debt facilities, and usually limits exposure to about $15 million per client. Even with smaller transactions, the bank is as busy as it wants to be.

“New deal flow has been very good. Many of our clients are growing organically so our increase in outstandings is mostly through initiated drilling programs and acquisitions,” says Vick. “We are seeing deal flow from midsize E&Ps selling older, less productive properties to smaller independents.

“Bank debt is usually the least expensive form of financing a company can get. Our bread-and-butter product is a revolving line of credit in the $1- to $10-million range, secured by proved, developed, producing reserves.”

The bank also offers term loans with slightly higher advance rates and can customize structures to suit a client’s particular needs. The bank focuses on clients that either are headquartered in the Rockies or have significant production there.

At present, American National has some 50 borrowing relationships with Rockies-based companies. The bank currently has roughly $150 million in total commitments with about half of that amount outstanding.

“Many start-ups and smaller independents are grown from managers exiting larger E&Ps,” he says. “It seems there is a never-ending cycle of experienced managers from larger corporations that now want to make some money for themselves. We’ve successfully helped a number of those teams.”

Those experienced managers should have a bright future in the Rockies. Much of the resource base for future U.S. gas production will be derived from the region, as production here grows while other regions shrink, says Vick.

The biggest challenge to that growth is pipeline constraints.

“We are going to be pipeline constrained from time to time. It runs in cycles. For now, the Rockies Express Pipeline (REX) has been very good for producers, but pipeline constraints are something we have to live with. We factor in a long-term average of differentials when we make loan proposals.”

In April, the Rockies gas basis differential to Henry Hub shrank to $1.50 per thousand cubic feet, down from April 2007’s $2.50. In late May, the 713-mile REX West completed line-pack operations and gas began flowing from Wyoming to Missouri.

Another uptick advantageous to Rockies players is 3-D seismic technology. Much more so than in the past, explorers are using 3-D to identify small structures of bypassed production between larger features. “Clients can see structures more clearly on 3-D, which allows a higher drilling success rate. We have several clients that have been successful with this in Kansas and parts of the Rockies.”

The best part of being a community bank is that “we work with local customers and are the lead arranger on all of our deals,” Vick says. “We set the terms, negotiate with our clients and structure something that fits both sides. When you take syndicated pieces of deals arranged by other banks you miss all the fun.”

Capital gains

While Rockies energy lenders are enjoying increased deal flow, another capital provider is preparing to shield its clients from politicos who may want a larger piece of the income pie. Successful E&Ps’ legacy assets, producing profitably since the time of $20 oil and $3 gas, continue to return healthy dividends and enjoy solid credit ratings, but there may be a dark cloud on the horizon.

Even as E&P master limited partnership structures with their accompanying incentive distribution rights fall from favor, a creative new financial structure has been born. The brainchild of Denver investment firm Plexus Capital LLC, it has already proven to be an effective tactic against politicians who threaten to enact new capital-gains taxes on energy.

“Let me tell you about a creative financial structure that I think is the right thing for today’s environment of high commodity prices, low interest rates and the expected future increase of long-term capital-gains tax rates,” says Plexus Capital’s managing partner Wayne Williamson.

It’s a financial structure for assets currently held by a non-C-Corp. “We created this and have already executed it three times.”

Here’s how it works: For producers that wish to monetize their assets without giving up the upside, a bankruptcy-remote special purpose entity (SPE) is formed. Owned by the producer’s owners, it acquires the assets with low-cost amortized debt provided by a financial institution like Prudential, with recourse only to the SPE. The cost of capital can be reduced by using an insurance wrap to guarantee either the production or the debt itself.

“If oil or gas properties have been owned by a producer for at least 12 months, the producer can sell those assets to the SPE, and trigger a long-term capital gain at today’s rate. The basis of the assets will be stepped up in the new SPE,” says Williamson.

The bottom line is low cost of capital at a favorable advance rate, perhaps equivalent to a purchase price, with low risk because the SPE has no other enterprise risk outside of producing these specific assets, he says. As always, future production can be hedged.

“The monetization could be as much as 80% of the PV-10 value of the properties,” says Williamson. “If additional consideration is required to achieve a fair purchase price, either subordinated debt or a note between the SPE and the producer can be arranged.

“Essentially, the funder lends to the SPE, the SPE pays the producer and none of the debt is recourse to the producer, which has bifurcated its capital structure with low-cost debt and locked in current commodity prices.”

Plexus has done this for Aspect Energy LLC (for $40-million and $30-million transactions), Manti Operating Co. and Tri-C Co. (for a $130-million joint transaction) with short-lived (half-life under two years) Gulf Coast properties.

The arrangement works particularly well for short-lived Gulf Coast properties because the producer is accelerating the future income-tax liability but at a much lower long-term capital-gains tax rate than the ordinary tax rates he would otherwise realize over time. The longer-life nature of the properties, the less beneficial the tax strategy, due to the present value of the future ordinary income tax becoming less than the current long-term capital-gains taxes paid.

It also helps to self-monetize the properties because investors are not currently enamored with short-lived properties and will not pay as dear a price for them as long-lived properties.

Plexus is having a good year, working on nine deals that keep the six-person firm fairly busy, and has closed more than 23 deals year-to-date. “Our job in any transaction is to transfer risk to the entity that will charge the least amount to take that risk, to lower the cost of capital, and to anticipate where problems might arise, so we can be ready with solutions for our clients,” Williamson says.

Most of Plexus’ clients are private entities, although so far this year the firm has been engaged by a few public companies. Most of the funds for its capital deals, whether debt or equity, come from private-equity firms, such as EnCap Investments LP or Quantum Energy Partners (a former Plexus partner), hedge funds, institutions like Prudential and American International Group Inc., or commercial banks.

Williamson sees a trend of money managers raising ever-larger funds, averaging some $1 billion, whereas a few years ago the average fund was about $300 million. Banks and fund managers are increasingly forced to place large amounts of funds into each investment or debt deal, to put money to work as quickly as possible.

“Most of the money is chasing resource plays and the value of those has gone through the roof,” he says. “It’s becoming more difficult to find capital for small deals. I was recently told by a major bank that a $100-million debt deal was too small. I was shocked. And this was before the credit-market problem.”

Plexus is currently working on a $600-million downstream deal. “We hope to have a senior piece that will be syndicated by a major bank. This amount gets their attention.”

The credit crunch isn’t affecting Plexus’ business now, but it had some effect during the past year. “Last summer, just when things started blowing up, we were approached to find a Term B deal for a local private producer looking for inexpensive financing to further develop its proved assets,” says Williamson.

“But no one was lending Term B money. So the E&P company ended up doing a different transaction, in which it sold a portion of its assets to a group that was willing to pay a price that provided similar returns upon the development of the properties.”

Meanwhile, oil and gas property values are increasing. “I talked to another large acquirer that said it tried to offer a PV-10 on total proved future cash flows, but the seller said it wouldn’t take less than future cash flows discounted at 8%. That’s amazing to me. I think the risk associated with the return they are expecting is out of whack.”

In another deal, Plexus raised capital for Belize-based Belize Natural Energy Ltd., a small E&P with drilling locations in the Spanish Lookout district of the Corozal Basin.

“They discovered the first production in Belize. The client didn’t want to give any equity kickers, and it had only recently started producing, from only two wells, so there was a concentration of risk. My client wanted low-cost debt, so that was a tough one.”

Plexus negotiated with Standard Bank Group Ltd., based in Johannesburg, South Africa, which agreed to provide the financing. The deal was subsequently syndicated as more foreign banks were brought into the transaction, which turned out well.

Plexus’ most unusual deal involved a Golden, Colorado-based company called Luca Technologies LLC. The firm studies resident methane-generating micro-organisms in substrate samples taken from coalbed-methane or oil properties in the 110,000-acre Monument Butte Field in northeastern Utah, and also in the Powder River Basin of Wyoming. Luca hopes that, by stimulating micro-organism activity, it might turn finite energy reserves, such as oil, oil shales and coal, into methane farms capable of long-term sustainable gas production.

“They put a substantial amount of their own capital into research and sampling in those areas and they were looking for about $10 million of venture capital,” says Williamson. “That small size doesn’t get U.S. institutional investors very excited, so we took it to BASF of Germany. They funded it because they are interested in the scientific approach to this technology.”

Plexus is also amenable to working with E&P start-ups, especially because those without assets usually have no valuation issues. The firm values start-up funding based on how much back-in (gained ownership as an entity realizes agreed-upon upward levels of value or earnings) the client is going to get and the arrangement of back-in thresholds.

“Recently those numbers have gotten bigger. I’ve seen some transactions where producers don’t go through a money manager at all, but go directly to an institution to get back-ins as high as 50%. It’s unusual, but I have seen that happen.”

Overall, Plexus works with A-, B- and C-rated clients. “The ones with better track records get better terms, better back-ins and lower hurdles. Those that are, for the first time, using OPM (other people’s money) may not be able to get the best terms.

“Still, I can’t think of any industry that is more interesting than oil and gas. Putting these deals together is like putting together a puzzle, and every deal is different.”

Reversed deal flow

Jon C. Hughes, managing director for global markets and investment banking in Merrill Lynch & Co.’s Denver office, agrees that interesting events are starting to affect transactions in new and different ways in the Rockies. New gas-price differentials, hedging markets and a reversal of asset-transaction flow are changing the face of producers’ operations.

“The big picture is that there are enormous gas resources here in the Rockies and prices are good,” says Hughes. “We had basis-differential problems affecting transaction values in 2007, when some producers were selling gas for less than $1 per thousand cubic feet at times. That was a $4 to $5 basis differential.”

The 2008 opening of the REX pipeline made a significant difference.

Hughes also works with Merrill Lynch Petrie Divestiture Advisors (MLPD), the focus of which is asset and private company sales. MLPD was formed in 2006 when New York-based Merrill Lynch & Co. Inc. acquired Petrie Parkman & Co. Since 2003, the MLPD team has been involved in more than 60 energy-related divestiture transactions, representing an aggregate value of more than $26 billion, usually advising on deals ranging from $250 million to $5 billion.

“Transactions are easier today than they have been in the past. While there has been a perception of the Rockies as a place of boom and bust, two factors have changed that—planning and hedging,” says Hughes.

The Rockies energy industry is moving toward better infrastructure planning, he says, due to recognition of the substantial resources. Producers and operators are becoming more efficient and forward thinking as they organize to develop the basins. Although REX has solved today’s bottleneck, producers are already working toward planning future pipeline capacity.

“Also in the past, it was difficult to close transactions during periods of high commodity-price volatility. The difference today is the liquidity in the commodity-trading markets. Virtually every large transaction these days is hedged because a buyer wants to lock in at least a portion of his acquisition economics.

“With Enron gone, and the hedging taken over by strong financial institutions like Merrill Lynch, Goldman Sachs and Wells Fargo, we now have a very liquid market. Buyers will happily lock in $10 gas for the next three years to have confidence their cash flows will fund expected development costs.”

The average Nymex price for natural gas has risen to $10.49 per million Btu from $2.41 a decade ago.

MLPD routinely tracks average transaction prices and compares them with a gas-oil blended Nymex average strip price to illustrate value available to acquirers in this high-price environment. The margin’s historical margin has climbed from $1.59 in 1998 to $6 this year.

As Rockies wellhead gas prices have changed to bolster values and accelerate transactions, gradually the buyer-seller roles in U.S. oil and gas asset transactions have also changed, he says.

“The direction of asset deal flow has changed. In the past, the general rule was that companies held assets until depletion, while the larger companies might sell off some noncore marginal properties to clean up according to the 80-20 rule.”

Today, producers plan according to portfolio theory, constantly evaluate a suite of properties for a balance of oil and gas, long-lived or short-lived, operated or nonoperated, mature or immature and geographic diversity. The trend has moved away from a norm of mature assets flowing from larger companies down to smaller, private companies to be nursed along to depletion.

The current situation is that small, private producers are building high-quality packages specifically for sale up the food chain to larger and, often public, entities.

“The flow direction has reversed,” he says. “In many cases, these private owners keep extremely good documentation and land records to make the due-diligence element of sale to a public company buyer go smoothly. They have this business model in mind when they start the company.”

He also sees majors “coming home,” looking at assets in the U.S., going to data rooms where historically they wouldn’t do that. That re-look at the U.S. is due to a combination of the large amounts of capital the biggest companies have to spend and a limit on international opportunities due to resource nationalism, Hughes says.

But there haven’t been many large corporate transactions yet this year, possibly because it will take some time for the majors to get comfortable with the operational intensity of some of the independents’ projects.

“If one hasn’t looked in a while, the size of some of the U.S. producers will be shocking. There are a half-dozen $30- to $50-billion-market-cap independents out there. That’s big. Not so long ago, the only energy companies that size were the majors.

“These large independents and some of their smaller brethren, especially those active in resource plays, like the ones we have in the Rockies, are building asset bases that will be attractive to the majors.”

Hughes says the U.S. is in a new energy-price paradigm, with gas prices likely to stay in the $8 to $12 range and $80 to $120 for oil. He doesn’t think oil will fall back to $60 again in the near future.

“We’ve reached practical peak oil. We just can’t produce enough to keep up with expected demand growth, regardless of conservation and fuel efficiencies. We have enough oil for 100 years, but it is not going to be cheap oil. We don’t see a bear market for energy prices.”

Accounting

Rivington Capital Advisors LLC, a boutique investment bank with some 50 transactions to date, now also offers its clients a fully staffed accounting department to free producers to do what they do best.

“Our total deal volume is close to $3 billion,” says co-founder Christopher R. Wagner. It does five to seven deals per year on average, focusing on small- and midcap private E&Ps. Its 23 staff members have experience with deals of $3- to $250 million in size, with a fairway of $40- to $100-million per transaction.

In addition to its everyday modus operandi, Rivington, through an affiliated entity, has a group dedicated to providing full-service accounting and finance for its clients, especially start-ups, that don’t have oil and gas accountants in-house. Within its core markets—Denver; Austin, Texas; and Bakersfield, California—there is a lack of adequate E&P accounting talent, he says.

“It’s an easy transition for our investment-banking clients to depend on us for accounting and finance services,” says Wagner. “It allows them to focus on the technical merits of their business. We have 15 clients in our accounting-services group now.

“Unlike other outsourced accounting groups, our people will do everything from the most menial data entry to the controller function. They work on an hourly or a fixed basis, tailoring it to the needs of the independent.”

Wagner categorizes 2007 as a “fairly lucrative year in deal volume,” and says Rivington’s investor group seems to be growing every day as more money flows into the upstream market. He expects 2008 to finish as a strong year.

“As long as we see commodity prices stay high, in the $70-plus range, we’ll see continued high acquisition and development levels. Any activity like that is good for us. Also, we tend to do best when the market is volatile, as opposed to constantly being in high- or low-price environments. I think we will see that continue for some time to come.”

In the Rockies area, the definition of a small-cap company includes a very wide range of value, he says. “On the private side, of course, the small-cap can be a start-up. But we would define small caps as any company from a start-up to $1 billion in enterprise value. Most of our clients run in the $100- to $300-million enterprise value range.”

Rivington’s transaction portfolio is normally split between senior, second-lien and mezzanine debt and private equity. “But that division sort of ebbs and flows. It seems, since 2007 when the credit markets became choppy, there has been more equity activity,” says Wagner.

Most of Rivington’s clients are experienced management teams with new acquisitions, assets or development plays in hand. To best serve them, Rivington’s staff is deliberately more open-minded, focusing on managing transactions on a success-oriented basis.

“When we get involved with a client, we are not asking for retainers or break-up fees. We are working toward the same goal as they are—closing the transaction. That’s where we earn our fee. Because of that, we do a lot more work.”

While Rivington is predominately E&P-focused, it has experience with oilfield-service transactions and has pitched a few midstream deals, but the market is growing more receptive to the longer-lived, resource-type plays, he says.

“Resource plays have more stability in their profile. Investors like those that are a little less mature, with potential for future production and operating-expense reductions. We are also seeing more E&Ps looking for project equity.”

Defensive stock

E&P stock values are not the only beneficiaries of high commodity prices. U.S. Bank, a commercial energy lender, avoided the sub-prime mortgage crisis and has seen its stock price hit a 52-week high.

Much like producers, “we have gotten some press lately as a defensive stock,” says Mark Thompson, U.S. Bank senior vice president and energy-division manager.

“All of the name-brand E&P independents are growing. As their bank groups grow, we are being invited into more credit arrangements. We booked 28 new borrowers in 2007 and about eight so far this year. We now have a portfolio of 80 producers totaling $2.1 billion in a petroleum-segment portfolio of just over $3 billion,” says Thompson.

The average loan size of U.S. Bank’s energy division has grown from about $20 million five years ago to $30 million today. It has loans ranging in size from $2 million up to about $75 million, with a sweet spot between $30- and $50 million.

Typical new deals range from $40- to $60 million, which account for some of that increase. “We do have some horsepower and we are willing to put it to work,” he says.

Like most energy lenders, U.S. Bank is finding loan demand to be very strong at a time when credit is becoming less available.

“I would say that credit structures are getting stronger,” says Thompson. “Even stretch loans are becoming less aggressive and there is pressure in the credit markets to raise loan-pricing grids. Although the Federal Reserve has been lowering short-term rates, long-term rates really haven’t followed.

“So, the liquidity premium has been expanding and has been since June 2007. We first noticed it affecting oil and gas producers when talking with a Denver-based E&P last summer,” he says.

At the time, Forest Oil Corp. was seeking a private placement of $750 million of 7.25% senior notes due in 2019 to finance a portion of a corporate acquisition.

“They indicated that the cost of high-yield debt had jumped 75 basis points from where it was just two weeks earlier, giving us an early indication that the interest-rate environment was changing. Now, everyone’s cost of funds for long-term money has gone up, including banks’ costs of funds, and this will likely lead to an increase in loan pricing for producers,” he says.

Also, U.S. Bank’s price decks have been increasing gradually during the past eight years, since the previous major oil-price drop in 1998, to remain in sync with other energy banks in large syndicated-loan arrangements. For oil, its deck is $65 per barrel in 2008, $62 in 2009 and $55 long term. For gas, its deck is $6.75 per thousand cubic feet for 2008 and $6 long term.

In fact, most all energy banks’ long-term price decks for commercial loans are still in the $55 to $60 range, representing about half of the current market price of oil, he says. The difference between loan price and market price continues to create an opportunity for mezzanine debt and equity providers.

It’s no surprise that the bank’s deal flow is increasing. During the past three years, U.S. Bank has increased its commitments to oil and gas producers a consistent 31% per year. The number of credit relationships has increased an average of 23% per year during the past four years.

To keep up with growth in the bank’s energy-lending sector, it has expanded its staff to 19 oil and gas bankers, up from 14 people three years ago. The staff includes two petroleum engineers, one engineering technician and five relationship managers.

The bank plans to increase those numbers again in the near future, in response to its increasing business. Also, it has formed a new team to serve its independent power-producer clients involved primarily in gas-fired power projects, and to evaluate clean coal, wind and other alternative-energy credit opportunities.

Meanwhile, as new business comes in, existing business is lost as a result of customer liquidity events. “We have experienced about $500 million per year in loan pay-downs resulting from high-yield debt and equity offerings, as well as property sales or outright company sales.

“We have to overcome this $500-million-per-year headwind to maintain our growth rate at 31%, implying that our annual growth on a gross basis is probably closer to 50%,” says Thompson.

“It’s clear that the high-yield debt and equity markets accept today’s oil and gas prices as sustainable. These markets continue to be very strong and available to the petroleum segments. Energy continues to be one of the few bright spots.”

Prime over Libor

“This year, financial and capex spending covenants have gotten tighter,” says Ronald M. Barber, senior vice president of the Rockies region’s largest independently owned investment-banking firm, W.G. Nielsen & Co.

“Surprisingly, while leading interest-rate indices have gone down, capital providers are now assessing risk a bit more intelligently than they were a year ago, so the interest rates on most deals haven’t fallen because the spread over Libor (London interbank offered rate) or (U.S.) prime has actually broadened,” he says.

In the past, many of the firm’s deals were based on Libor. However, due to recent dollar devaluations, W.G. Nielsen’s bankers are placing more debt transactions based on U.S. prime where they have that option with the debt provider.

“It’s no longer Libor plus 250 basis points. Prime is much more attractive now, but that could change, if and when the dollar strengthens,” he says.

While the firm has placed a number of Libor-based loans, it also offers a mix of terms in its structures.

“We’ve had a number of debt structures with a blend of Libor and prime,” says Wayne G. Nielsen, president. “A variable rate can be locked in for 30, 60, 90 days or longer, based upon one of the indices or some kind of U.S. Treasury index.

“There is a variety of possible themes and I think that managers and CFOs are becoming far more knowledgeable about these options. This is a dynamic interest-rate environment.”

As for new capital trends, the firm has seen a number of instances where large private-equity groups and equity funds are moving in to fill the debt gap that has been left by the national commercial banks, which have pulled back from what they consider to be risky lending. Many equity providers are now using cash to fill the debt void.

Additionally, some sub-debt and mezzanine providers may include equity-conversion provisions in transaction structures.

W.G. Nielsen handles transactions as small as $5 million and as large as several billion. On the high side, the firm claims the largest single transaction in Colorado, valued in the billions, although it was for a non-energy-related entity. Its average transactions range from $25 million to some $200 million with a sweet spot between $50 million and $1 billion.

Deal flow continues to be good. Nielsen quotes Thomson Reuters data to determine U.S.-based transaction trends. “Interestingly enough, for the first quarter of 2008, the aggregate number of all M&A transactions of privately held companies this year compared with the past few years, is about the same.

“However, the dollar value was off about 10% this year,” he says. His take is that the value proposition of larger deals has fallen, but the middle-market sector is be healthy.

“The middle market for well-positioned companies, with good management, historic revenue and decent pro forma earnings are still commanding rational prices. But the debt component has been somewhat harder, making some of the valuations a little more challenging,” Nielson says.

“We are also very strong in the oilfield-services sector,” he says. “We’ve recently done a large recapitalization deal for a drilling-rig company. We understand the economics and drivers for that sector. We often have institutional investors asking us for information on the next oilfield-service deal.”

While Nielsen admits that overbuilt rig capacity can be problematic, he says, “We will play. We have financed land-drilling rigs, and continue to be involved with rig service companies. We like oil rigs.”

Why? Barber says, “I think we will see a modest increase, maybe a couple hundred dollars per day, in rig dayrates from the Canadian border all the way to Texas by the end of this year. We are also working with two fluid-hauling service providers. There is not enough wastewater disposal in the Rockies. We think that business will grow as well.”

While a large part of the firm’s business is based on oil and gas, it is willing to look at alternative-energy deals that make sense.

Download the PDF of "REAL ESTATE MARKET IMPACTS OF OIL & GAS INDUSTRY IN METRO DENVER," a report on a study prepared for the Colorado Oil & Gas Association by Cushman & Wakefield Research Services, 2008.