Long Gas, Short Capital

In today's capital markets, being long natural gas isn't viewed favorably by investors, and few equity or debt sponsors are pursuing natural gas opportunities. Therefore, the question of how to finance a natural gas-levered E&P company looms large.

The knee-jerk response has been to say go long oil, given that the West Texas Intermediate (WTI) crude oil price was recently higher than 40 times the Henry Hub natural gas price.

During the latter half of the past decade, high gas prices, the proliferation of horizontal drilling technology and shale and other unconventional res - ervoirs sparked a land grab with accompanying high levels of drilling to hold acreage. Today, gas producers hope that hyperbolic decline curves, coupled with a dramatic drop in drilling, will correct low gas prices.

Despite languishing prices, however, our discussions about financing natural gas and gas-weighted companies have turned up a small group of investors in every segment—"contrarians"—who are interested in these deals. They are willing to be involved longer term and expect gas prices to rebound in the next couple of years.

Still, looking across the capital structure, from bank debt to term debt to public and private equity, the buyers are few.

Funding uneconomic projects

Without the presence of liquids or oil, dry-gas reservoirs are, for the most part, uneconomic to drill at current gas prices. At best, these reservoirs are now lower-return opportunities on a drill-bit-only basis. On a full-cycle-return basis (including the cost of acreage, G&A, cost of capital, corporate taxes, and time value of money), only a few first-mover companies with low acreage costs and some of the best rock are generating positive returns.

Exacerbating the situation is that the fall in natural gas prices was not accompanied by a corresponding fall in oilfield service costs. Therefore, as we evaluate assets and companies on the market, it is difficult to value nonproducing reserves. Attributing even small amounts of value to acreage or undeveloped reserves using current natural gas prices typically would reduce the already paltry returns of many wells to below most companies' economic hurdles.

Offshore, although acreage is not the hurdle for purchasing assets, the present value of asset retirement obligations (ARO) has a significant negative impact on mature gassy assets, particularly given the rising costs of decommissioning and plugging and abandonment work. While we still see value for specific nonproducing dry-gas assets, the list is small. A normal distribution of returns for all natural gas projects suggests that only 10% of projects are economically viable under a $4-per-Mcf gas price, while 90% of known undeveloped natural gas prospects are economically viable at $6.15 prices. The mean on the distribution suggests that half of all U.S. gas projects are economically viable at $5.14 natural gas prices.

Term debt markets continue to offer an alternative to commercial banks, while MLP/royalty trust vehicles can be superior to equity offerings, for the right assets.

Although it sounds as if all natural gas buyers would simply be bottom feeders, the profile tends to be mature, longer-cycle companies and investors. They are looking five to 10 years out and see slow but steady growth in demand for the commodity. And, if the pundits who say Marcellus shale gas and associated gas from liquids-rich reservoirs are adequate to maintain current levels of production should prove wrong, natural gas prices could double rapidly.

The two issues that are difficult to overcome are the spread between buyers and sellers of gassy properties and the financing of these purchases. From an economic standpoint, it is difficult to justify paying more than proved developed producing (PDP) value for gassy assets in terms of full-cycle returns based on current prices. Sellers want to get paid for their undeveloped and unevaluated acreage, and given purchase prices just a few years ago, they think they are leaving a lot of value on the table. Regardless, it is a buyers' market, and given the lower relative return of natural gas properties, buyers need to find the lowest cost of capital.

Debt

Commercial bank debt has been a go-to option for many producers, because it provides the lowest cost of capital. Bank price decks move with the strip, albeit at very conservative price points. The consensus from our conversations with commercial bankers is that natural gas price decks have been lowered to $2.50 to $3 per MMBtu, because the price deck of the past year has been held artificially high. Further, bankers expect this deck could be lowered again based on continued commodity-price weakness this fall. The result would be a liquidity crunch for some gassy E&Ps, even those having as little as 30% to 40% dry-gas production.

Already this year a number of new credits have been turned down by loan committees because they are gassy. Hedging helps, but with the collapse of the forward curve, most operators don't see an economic benefit from hedging relative to their bank price decks. This is a material difference versus a year ago.

The number of players looking at E&P credits is also waning. Part of the outgrowth of the European debt crisis has been a retreat by European banks. BNP sold its energy portfolio to Wells Fargo, and a number of other European banks have begun to scale back U.S. operations and reduce capital commitments. The combination of fewer lenders and lower natural gas prices does not bode well for gassy E&P companies in the short run.

Below commercial bank debt lies the second tranche—second lien, or mezzanine debt. By definition, this level of debt comes with more security risk, longer duration and higher cost of capital. Many companies have used mezzanine debt financing to grow through project development, including expanding infrastructure and drilling undeveloped locations outside of what senior credit will cover. Although less risk averse, our market feedback is that mezzanine debt is only available to the best companies in the most desirable zip codes.

Longer-term paper than what banks provide has recently been priced at rates just a bit higher than commercial bank debt. High-yield paper also can be sold that both allows replacement of commercial bank debt and fills the role taken by mezzanine debt. Buyers of high yield want to first stress test gas reserves to make sure there is enough asset and EBITDA coverage based on low commodity prices. The good news about terming out debt is that it is interest only, and there is no semi-annual redetermination involved.

We looked at high-yield issuers sorted by gas percentage of proved reserves in late February. Although the average coupon for natural gas-weighted companies is about 61 basis points higher than oil-weighted companies, the average offering yield between oil- and gas-weighted names had a spread of 0.69% and the current yield to worst spread has further expanded to 1.57%. This suggests that the cost of issuing natural gas-weighted paper has increased. Part of what is driving yields up and prices down are concerns about liquidity reductions, falling EBITDA from lower gas prices, low-return projects, and buyer preference.

Private eyes

Private-equity investment in energy continues to expand, and one would think that given an average five-year investment horizon, a number of firms would be keen on natural gas. However, numerous funds have stated the opposite, both privately and publicly. They believe the dislocation in the oil and gas market will persist well into the future. With abundant supplies of natural gas and slow adoption of natural gas as a fuel source across many industries, low prices and marginal economics do not generate high-enough returns to attract private equity. Further, most private-equity funds recognize that it is difficult to make sufficient equity returns through an acquisition strategy without a bet on commodity prices. And that bet can be made in the commodity markets without having to fund a company.

Nonetheless, many private-equity firms have legacy investments in gas-weighted portfolios. At least two funds have told us they would look at a natural gas investment, but it would be highly dependent on management and economics. A couple of contrarian companies backed by private equity are looking for gassy assets, but they appear to be the exception rather than the norm.

Stock price valuations should reflect the discounted future net cash flow of a company. Falling commodity prices have a profound impact on valuations as margins get squeezed, financial metrics fall, and growth rates drop, pushing developmental cash flows further into the future. E&P stock prices have reflected a premium to the cash market for over a year due to the contango forward natural gas curve. However, supply rising faster than demand has turned the curve downward.

One would expect falling prices to damage gassy E&P equities, and for financially leveraged and/or unhedged producers, that has been the case. But not every gas-weighted company has suffered. In fact, some of the best-performing equities last year were gas-weighted names. Part of the equity performance spread between best- and worst-performing gas equities is a function of margins. Companies such as Cabot Oil & Gas Corp., Range Resources Corp. and EQT Corp. performed well. Not only did they have some of the best margins but also they were the subject of many takeout rumors. The sales of Petrohawk Energy Corp. and El Paso, two gas-levered names, also generated returns in the top decile of performers.

Given these returns, would the equity markets be receptive to these companies tapping the equity markets to sell common equity? Rex Energy Corp. recently went to market and its stock traded down 10.8% from $10.61 at the time of its announcement to price at $9.46 per share. Some of the top-performing natural gas companies could access the equity markets, but part of the reason they are top performers is that they are financially sound.

Many portfolio managers have suggested that there is still a premium in these gassy names, and with sub-economic drilling prospects and a bad commodity macro, it has become somewhat of a buyers' market for gas-weighted equities. The further argument is that earnings momentum is still negative, and trough earnings may not occur for natural gas companies until at least second-quarter and possibly third-quarter 2012. That suggests the equity markets for gas-weighted names could reopen this fall, but no one has confidence in the commodity prices the equities would reflect or whether a continued liquidity squeeze would create the need to tap the markets.

VPPs, MLPs, JVs

As an alternative to conventional sources of capital to fund drilling, many operators are running through the alphabet to come up with solutions. Over the past couple years, volumetric production payments (VPPs) drew interest, given the strong forward curve of the commodities. With the forward curve dropping, however, many operators believe this is a low-incentive option to essentially forward sell natural gas to prompt more drilling. The margins are too tight to pursue this option.

Shown are high-yield issuers sorted by gas percentage of proved reserves.

A number of oil and gas companies have pursued joint ventures (JVs) over recent years as a way to recoup acreage costs and fund drilling. The surrender of interests for capital is basically a way to sell a working interest in a project over time to an entity interested in the commodity, technology or the returns. More recently, JVs for gas-weighted assets have waned in favor of oil-weighted projects, and many gassy JV partners have urged a slowdown or stoppage of drilling in certain areas given falling prices. One exception is Western Canada, where other letters in the alphabet—LNG—have captured attention. There is still interest in natural gas assets that can be used to fuel the building of Kitimat, which would have ample liquefaction to export LNG to the Far East.

Shown are May 27, 2011, to May 29, 2012, equity returns unadjusted for dividends with the companies highlighted producing more than 80% of volumes from natural gas during 2011.

One avenue that seems to still hold merit for gassy companies is using a master limited partnership or royalty trust structure to capitalize assets. This format works best for long-life, shallow-decline properties where a healthy distribution can be paid to unit-holders. It remains a low-cost form of capital in a yield-hungry world, but not every property is a candidate. From an IPO standpoint, royalty trusts are being priced at 9% to 10% rates of return. MLPs in the production space are bringing 10% at IPO, although they can be seasoned down to 7% to 8%. For MLPs with at least 50% gas (excluding EV Energy Partners LP for the Utica shale and Constellation Energy Partners with no distribution), the seasoned yield is 8.9%.

There is no easy solution for natural gas producers seeking capital. There are still the "haves" and the "have nots," which produce dry gas, but the persistent problem is that economic returns are very difficult to generate with low natural gas prices, and the buyers of paper know this.

Industry buyers also understand these factors and want to price deals accordingly, so as to participate in a gas-price recovery. Biases notwithstanding, and provided there is a stable level of cash flow, we continue to see the term debt markets as an alternative to commercial banks, and we think that the MLP/royalty trust vehicle is superior to equity offerings for the right assets. The other obvious financing alternatives are to monetize midstream assets and noncash-flow-producing assets, and to batten down the hatches, cut spending and ride out the storm.

Michael Bodino is managing director of investment bank Global Hunter Securities LLC.