E&P "MLP mania" continues to gain steam, as several producers have announced or hinted during the past few weeks at intentions to form master limited partnerships (MLPs). While the MLP structure will become more and more prevalent, given the apparent disconnect between the in-ground value of long-lived, low-asset-intensity producing assets versus their value within an MLP, a closer examination suggests one size does not fit all.





In a report last summer, "Dawn of Upstream MLPs: Why This Changes Everything," Deutsche Bank's E&P research team pointed out the seemingly significant arbitrage gap that exists between market values of long-lived, low-capital-intensity assets and their implied valuation within an MLP structure. Since that time, several upstream MLPs have come public, and registered impressive performance since their initial offerings.

Further, more recent MLP-related announcements from a handful of independent producers have been met with broad enthusiasm, sending share prices higher and significantly increasing the risk of being "short" stocks in this sector.

Upstream MLPs seem likely to proliferate, and this has implications for E&P asset values. In light of the yield-starved nature of the market and the availability of candidate assets there is no reason why the domestic upstream MLP market-currently roughly a $5.5-billion asset class-couldn't eventually approach the size of the midstream MLP sector, which has roughly $125 billion in market cap.

If this is right, the resultant rush to accumulate long-lived, shallow-decline, self-sustaining assets offering PUD (proved undeveloped) reserve upside should augur a generic uplift in the asset values for MLP-style assets.

There is a caveat: one size does not fit all. One of the presenters at the IPAA Oil & Gas Investment Symposium in New York in April quipped, "Looks like I have about 20 minutes to come up with an MLP plan."

While the theme generally has significant merit, there are important complexities to consider, including taxes (newly acquired assets are best-suited, as their higher basis mitigates the tax "leakage" in an MLP monetization), use of proceeds (buybacks vs. acquisitions vs. accelerated drilling at the parent level each carry different growth ramifications), and the suitability of the properties in question (ideal assets offer low capital intensity, a stable production profile and a measure of drilling upside).

Key sector risks relating to the MLP thesis are threefold: long-dated commodity-pricing weakness impeding the ability to hedge, rising interest rate adversely affecting MLP valuations, and unexpected regulatory changes reducing MLPs' tax advantages.

Since the 2006 "Dawn of Upstream MLPs" report, several upstream MLPs have come public and posted impressive returns. The positive market reception seems attributable to the MLPs' collective success in the acquisition market, which has boosted distributions already in several cases, and institutional participation in this relatively new and scarce asset class.

On the back of this trend, a handful of companies has at least loosely verbalized plans to pursue asset monetizations. These developments underscore a well-founded belief that upstream MLPs will gain steam as the North American gas basin matures, particularly considering the appetite of a yield-starved investor audience.



A primer

Under a 1986 act of Congress designed to promote energy supply-legislation that arrived just as the oil market crashed-certain energy assets can be run in a partnership structure, known as an MLP. The key benefit at the company level is that effectively no tax is paid-liability is passed to shareholders as partners. The partnership benefits from no tax and a lower cost of capital.

The shareholders benefit from attendant high dividend yield, on which much of the tax liability is deferred. The reasons that upstream (that is, E&P) MLPs have not resurfaced until recent times surround historical problems with structure.

Distribution levels too high given depleting nature of assets. Many MLPs pay out 80% or more of distributable cash flow, leaving little cash flow to cover maintenance and/or growth. Because E&P assets are depleting by nature, it is difficult to generate the consistent long-term cash flows that are required to fund a sustainable distribution.

Too much debt. Most MLPs have been significantly debt-leveraged, which represents a further drain on the cash flows and introduces significant financial risk in the face of volatile commodity prices.

General-partner interest promoted at expense of limited-partner interests. In a traditional MLP structure, the general partner receives incentive distribution rights (IDRs) in a tiered fashion, which effectively leverages its exposure to rising distributions at a preferential rate vis-à-vis the limited partners. This has the effect of reducing cash available for investors and limits the attractiveness of the MLP structure overall.

Commodity-price volatility has a major effect on the valuation of upstream assets. While commodity prices affect upstream assets to a much greater extent than the midstream assets that are more commonly structured in MLPs, more recent improvement in out-year pricing and liquidity at the back end of the futures curve has increased the ability of companies to hedge away the longer-term price risk.

Limited access to institutional capital. Before 2005, the audience for MLPs was primarily limited to retail investors, constraining capital-raising in the sector. However, the American Jobs Creation Act of 2004 added MLP income to the list of allowed income for mutual funds, as long as funds do not invest more than 25% of their assets in MLPs, and do not own more than 10% of any one MLP.

In the research team's estimation, selected producing assets that are long-lived and low-risk in nature, offering significant development upside but requiring low maintenance capital, can be effectively used in an MLP structure.

If debt is limited and the production is mostly or completely hedged, the drain of interest payments should not seriously threaten distributions or the viability of the entity. As well, a payout structure more like a limited liability corporation (LLC), in which the general partner shares equally in the cash flows alongside limited partners, can avoid the "double dipping" problem outlined above.

The key characteristics of an oil and gas MLP, as summarized in a report by an MLP, Legacy Reserves LP, are a publicly traded limited partnership owning oil and gas producing assets; all excess cash flow is distributed quarterly to the unit-holders; the MLP retains 15% to 30% of its cash flow to reinvest in the properties to maintain and/or grow its production; and can grow through acquisitions and drilling; can issue debt and equity, and hedge.

Also, current oil and gas MLPs utilize two to five years of hedging to mitigate price volatility destabilizing distributions.

In its recent investor presentations, Constellation Energy Partners estimated that it typically takes three to five years to progress a typical producing asset from an early stage to a level of maturity appropriate for drop-down into an MLP.

In some instances, the research team's work suggests that, depending upon the play type, the timeline might be five years or longer before a given well "turns the corner" and its decline flattens out sufficiently to warrant inclusion in an MLP.



Valuation arbitrage

The upstream MLP universe was trading in late April at an implied multiple of proved reserves of $4 per thousand cubic feet equivalent (Mcfe) or higher, yet the Deutsche Bank E&P research team's E&P coverage universe, which consists of C-corp oil and gas companies, was trading at that time at merely $2.62 per Mcfe on proved reserves. It is this valuation disconnect that seems to be giving rise to the current wave of interest in MLP formation, given the implied "step up" in asset values that might be achieved in a monetization scenario.

The research shows that the valuation disconnect is attributable to two primary drivers, the most obvious of which is the tax shield and/or the avoidance of "double taxation" that burdens C-corps (whereby the corporation pays taxes on its income and the corporation's shareholders also pay taxes on the corporation's dividends).

MLPs allow for pass-through income, meaning that they are not subject to corporate income taxes. Instead, owners of an MLP are responsible for paying taxes on their individual portions of the MLP's income, gains, losses and deductions. Specific to upstream assets, given the pass-through of the tax shield afforded by depletion expense (high-basis assets are particularly effective in this sense), the distribution to unit-holders is often partly or largely tax-deferred.

This too likely accounts for a significant portion of the step-up in value, although the ability of producers to utilize intangible drilling costs created by their oil and gas drilling capex to shield income at the C-corp level would seem to diminish this advantage somewhat.

The second driver for this valuation arbitrage, and arguably the more important one, relates to the seemingly insatiable demand for yield in today's equity markets.

Given their nature as steady cash-generating yield instruments, upstream MLP assets are typified by long-lived, shallow-decline reserves with a high degree of production visibility and relatively low future development costs burdening the assets. In contrast, traditional E&P assets carry a fairly significant level of reinvestment risk given their depleting nature, and the fact that many upstream portfolios include undeveloped reserves and abandonment liabilities that represent future capital requirements.

When structured within a "pass-through" vehicle like an MLP, the mature, lower-risk, shallow-decline reserves can be capitalized at a higher valuation as they are "comped" against other yield instruments offering similar bond-like characteristics.

To illustrate the arithmetic behind this, let's assume that a mature collection of wells generating $50 million per year in EBITDA (earnings before interest, taxes, depreciation and amortization) will require approximately 20% of that amount ($10 million/annum) to be reinvested in order to maintain flat production. If incorporating a coverage ratio of 1.25 times to maintain flexibility, that would reduce distributable cash flow from $40 million to $32 million ($50 million less $10 million in maintenance capex less an $8-million cushion).

Capitalizing that $32-million distribution at a 7.5% yield (which would seem to compensate for the inherently more risky nature of the cash flows from a depleting E&P asset vis-à-vis a midstream asset) would generate an implied MLP valuation of $427 million. This implies this collection of wells would be valued at an EBITDA ratio of 8.5 times-or $427 million divided by $50 million-which is much higher than the median multiple for the research team's coverage universe of E&P C-corps, currently 6.5 times.

This math suggests that the lower the assets' maintenance capital requirements, and the lower the MLP's yield, the higher the implied MLP valuation (as a function of EBITDA) should be. While clearly not every asset is well-suited for an MLP monetization, it becomes easy to see that, for the right type of asset, the valuation uplift could be substantial.



Who wins?

While upstream MLPs will become more and more prevalent during the next few years, producers don't need to rush into MLP monetizations to benefit from this growing trend. As upstream MLPs as an asset class grow in favor, competition to acquire candidate assets will heat up dramatically, likely supporting broad valuation uplift in longer-lived, low-capital-intensity assets.

During the past several years, the team has emphasized asset intensity as a core stock-picking framework, as a producer's ability to overcome depletion (via decline-curve mitigation and/or cost efficiency) is absolutely critical to the E&P value proposition.

An analysis of 18 C-corp E&Ps shows current rankings under the research team's asset-intensity metric, which reflects maintenance capex as a percentage of projected cash flow. According to this analysis, the gradual closing of the yield arbitrage gap described in the previous section will work in favor of further outperformance for all low-asset-intensity stocks, irrespective of whether they directly participate in MLP monetizations.



Important issues

One key risk to the thesis is actually more of a generic threat to MLPs (upstream and otherwise) as an asset class: interest rates. As with other yield-oriented securities, MLP unit prices should be affected by their implied distribution yield as compared with alternative income-generating investments. While investors should bear in mind that rising interest rates could have an adverse impact on MLP prices, a couple of interesting back-tests suggest the historical correlation to interest rates is actually not as strong as one might think.

Other risks and considerations more specific to the upstream MLP category would include tax leakage, far-reaching effects on the parent and use of proceeds, the IDR structure and execution risk.

Tax leakage. Generally speaking, MLPs accumulate assets in one of two ways-when they acquire existing producing assets from others, or when a parent company carves out a subset of its own legacy reserves for "drop down" into the MLP. Notably, the drop-down is effectively treated as an asset sale, and thus creates a taxable event for the parent. The key advantage to forming MLPs with newly acquired assets relates to their higher basis, which serves as a tax shield that is then passed along to the MLP unit-holder.

That said, if a given producer's reserves are being sufficiently and severely undervalued by the equity market, the result can be materially accretive to net asset value, even assuming some tax leakage.

Far-reaching effects on the parent, and use of proceeds. When the stock market materially underestimates the net present value of the long-lived, mature PDP (proved developed producing) component of a given asset base, the opportunity to monetize those reserves at some valuation step-up is created. If, on the other hand, the market is indeed efficiently valuing a given E&P stock based on an accurate net-present-value assessment of its long-lived reserves, then an MLP monetization itself won't create value; rather, use of proceeds becomes the differentiator, as is the case with volumetric production payments (another form of "forward selling" an oil and gas production stream).

In instances in which the parent company forming the MLP has a mixed track record of creating value by the drillbit, investors may not look so favorably upon reinvesting MLP proceeds into accelerated drilling activities. On the other hand, deploying those proceeds into share repurchases could inhibit top-line growth and increase leverage metrics like debt per barrel of oil equivalent. It is worthy of note that Fitch and Moody's recently negatively revised their rating outlooks for Pioneer Natural Resources' debt, citing similar concerns.

Along those lines, whenever assets are dropped into an MLP, investors should carefully scrutinize the ramifications on the "stub" assets that are left behind in the parent. As the steady, shallow-decline, cash-cow assets are pushed into MLPs, that might steepen the decline curve at the parent level, even if only slightly, and the loss of production could restrict cash flows available for maintenance and growth.

Companies must carefully size any prospective MLP monetizations so that the accretion in net asset value is material enough to merit the added management hassles and future reporting complexities, without hampering the sustainable growth potential of the parent's base assets. Further, investors should be aware of the potential for conflicts of interest between a parent company and an MLP subsidiary when it comes to evaluating new acquisition opportunities, and verify that certain prospective geographic areas are ring-fenced or at least that appropriate corporate governance procedures are in place.

To IDR, or not to IDR? Three of the six publicly traded upstream MLPs in existence in late April are structured as LLCs, which typically connotes that they do not have a general partner holding incentive distribution rights (IDRs). The advantage of this, beyond the very apparent benefit of equalizing the benefits and thus fairly aligning the interests of all investors, may include a lower cost of capital. Since the common unit's distribution growth is unburdened by IDRs, the cost of equity is essentially equivalent to the market yield.

Further, one could argue that eliminating IDRs enhances an MLP's ability to use units as acquisition currency, possibly making acquisitions more accretive at a given price.

Execution risk: longer-haul growth and sustainability of distributions. To remain competitive, an increasingly crowded class of upstream MLPs will seek to grow distributions at a faster and faster clip, which will increase the rate of their production treadmill via accelerated drilling and/or incite a greater pace of acquisitions, either of which heightens execution risks.

Investors should be attentive to the quality and suitability of the assets that are being targeted for acquisitions, and carefully weigh each management's ability to sustain and/or maximize production from those new assets. Expanding too rapidly beyond a partnership's geographic area of expertise may be a red flag that signals production problems to come, indicating potential threats to distribution growth. As well, excessive use of debt leverage could threaten the viability of the MLP in the event of a weakening in commodity prices beyond the horizon of its hedging portfolio.



Shannon Nome is managing director and lead E&P research analyst for Deutsche Bank, based in Houston. E&P research team members include associate analysts Scott Arndt and Eric Swanson. The team can be reached at 832-239-3144.