As production from some North American shale plays begins to mature and wells reach steady, predictable declines, E&P companies are increasingly evaluating the opportunities for funding growth offered by the upstream Master Limited Partnership (MLP) model.
Two key effects of the evolution of unconventional plays are: (1) the pool of mature, resource assets suited for upstream MLPs is growing rapidly, creating large potential for these assets to be packaged into this type of financing vehicle, and (2) E&P C-corps could be more incentivized in the coming years to sell or "drop down" mature assets to upstream MLPs as a vehicle to monetize their mature acreage and fund further unconventional drilling.
An MLP is a limited partnership (LP) or limited liability company (LLC) that is treated as a partnership for tax purposes and traded on a public securities exchange. Rather than issue shares of corporate stock, MLPs issue "units" representing partnership interests in the LP or LLC, and holders of these units are called "unitholders."
A distinctive feature of MLPs is their tax efficiency. While corporations are taxed once at the corporate level and again at the shareholder level when dividends are paid, MLPs have pass-through taxation whereby unitholders receive distributions directly from the MLP and the distributions are taxed only once at the unitholder level at their individual rates. Usually 80% to 90% of these taxes are deferred until a future sale of the units by the unitholder.
To qualify for this favorable pass-through tax treatment, at least 90% of the MLP’s income must be "qualifying income," which includes income from E&P activities. In general, income qualifies if (1) the income-producing activity involves mineral or natural resources, and (2) the activity involved is one of the following: exploration, development, mining, production, processing, gathering, refining, compression, marketing, transportation, or storage.
Another distinctive feature of most MLPs is that they must distribute all of their "available cash" each fiscal quarter and pay "minimum quarterly distributions" to unitholders. The predictability of these minimum quarterly distributions is why many investors find MLPs appealing. "Available cash" is generally defined as cash on hand at the end of the quarter, less reserves established for future capital expenditures and operational needs, plus working capital borrowings at the end of the quarter.
MLPs can be organized either as LPs or LLCs, as long as they opt for partnership taxation. In an LP model, the general partner (usually the sponsor) operates the partnership and generally holds a partnership interest of 2% or less. The general partner also typically holds incentive distribution rights (IDRs) entitling it to receive increasing percentages of distributions when MLP distributions exceed set levels. The limited partners in this model have limited voting rights and no control of day-to-day operations, as the board exists at the general partner level. Traditionally, most MLPs have been structured using the LP model. In the LLC model, there is no general partner and no IDRs, and the board is made up of directors who are elected by the unitholders. Legacy Reserves LP (LGCY) and LINN Energy LLC (LINE) are examples of upstream MLPs that operate under this LLC model.
Because there is no entity-level taxation, MLPs have a lower cost of capital compared to C-corps and therefore enhanced competitiveness with respect to acquisitions, and MLPs provide a tax-efficient way for sponsors to monetize assets at the IPO and through later drop-downs. Other advantages of the MLP structure to sponsors include the ability to partially monetize assets while maintaining control of the assets through the general partner and a significant interest in the assets through common or subordinated units in the MLP retained by the sponsor, favorable IPO valuations, and an attractive incentive equity structure through the IDRs.
Historically, the majority of MLPs have held midstream assets, which generally include long-term, fee-based transportation agreements. As a result, these midstream MLPs tend to have low maintenance capital expenditure requirements and limited commodity price exposure. Apache Oil Company, established in 1981, was the first "upstream" MLP created. During the decade to follow, over 100 MLPs were formed and roughly 30 of these contained E&P assets. However, companies that held upstream assets in MLPs during the 1980s eventually exited the market when commodity prices plummeted and they were no longer able to meet their minimum quarterly distribution requirements.
Among the reasons these early upstream MLPs failed were that they held oil and gas assets with high production-decline rates, which were not well-suited to an MLP portfolio, and hedging markets, which were not nearly as well established as they are today, were not vigorously employed to hedge against commodity price fluctuations.
After disappearing for nearly two decades, upstream MLPs began their recent resurgence in January 2006 when LINN Energy LLC went public. Currently, 14 upstream MLPs trade on public securities exchanges, with a current average yield in the range of 6% to 9%. What sets these new upstream MLPs apart from their 1980s predecessors is their asset portfolios and access to a more dynamic hedging market. These second-generation upstream MLPs have steadier cash-flow profiles than previous iterations, as they now almost uniformly concentrate on mature fields in well-established basins that have low production decline rates and long reserve life. Modern upstream MLPs also strive to hedge 50% to 100% of their production at least three years forward so they can meet and continue to increase their minimum quarterly distributions even when commodity prices fall.
Because the MLP structure generally requires an upstream MLP to distribute all of its available cash each quarter to its unitholders, the entity does not have the ability to amass a rainy day reserve as it would if it operated as a C-corp. Thus, the type of assets the upstream MLP holds are vitally important to its financial survival. These companies, therefore, focus almost entirely on proved acreage with low decline rates (generally defined as 10% or lower), which yield the sort of returns required by the MLP model. These new upstream MLPs do not typically engage in exploration; the average upstream MLP well vintage is over five years.
Assets held by upstream MLPs are also typified by lower maintenance capital expenditure costs than are associated with less mature properties. An upstream MLP’s capital expenditures tend to be for drilling expenses associated with low-risk development for production replacement, work-overs and acquisition of new suitable proved reserves and production. MLPs generally only drill to maintain current production levels—not for exploration purposes.
As upstream MLPs’ portfolios demand legacy assets with low decline rates, and many unconventional plays have now been producing long enough that a large number of their wells fit this profile, the pool of mature shale assets is growing rapidly and creates enormous future potential for upstream MLPs. Generally, it takes five to seven years for unconventional plays to reach maturity and be deemed MLP-suitable (with low and stable decline rates). Because it has now been roughly nine years since the first horizontal drilling programs began in US resource plays, and because those plays have produced well over 1.0 billion boe of oil and gas in the interim, one could expect that there will be a significant set of horizontal wells that could soon serve as available candidates for a new wave of upstream MLPs.
Many wells in the earliest unconventional plays like the Barnett Shale and the Haynesville Shale, which commercialized between 2004 and 2008, could already be considered MLP-suitable from a decline standpoint. Considering the fact that acreage held by upstream MLPs currently accounts for only a tiny fraction of total onshore US reserves, and the amount of capital being discharged currently into developing shale acreage, the potential for MLP-appropriate E&P shale assets appears imminent.
Rigzone.com reports that "The wave of exploration and shedding of mature assets by producers could result in a ten-fold increase in these MLP-appropriate assets." Through back of the envelope calculations, it is estimated that there are nearly $1.3 trillion worth of producing assets in North America, a large percentage of which likely already qualify for MLP usage. In 2008, production from resource plays accounted for only approximately 6 billion cfe/d, yet by early 2012, after production from major resource plays had grown drastically, such plays accounted for over 35 billion cfe/d. As shale plays continue to mature at such impressive rates, the industry should expect to see these unconventional assets employed more within the upstream MLP structure.
Another result of the rapid growth of horizontal drilling over the recent past is that many large E&P C-corps have considered dropping down their non-essential mature acreage into upstream MLPs in order to create the cash needed to fund higher-return shale development projects and acquisitions elsewhere. Because is it not generally cost-efficient for upstream companies to retain long-lived oil and gas wells in their portfolios, especially in light of the high-yield opportunities now available from resource play development, upstream companies generally see two options to monetize their conventional mature assets: either divest the acreage in an outright sale or, as many companies are beginning to consider, drop these assets down into an upstream MLP at a large discount.
Both options generate cash for the E&P company so it can divert that capital into its bread and butter activities: exploration and development of new, generally unconventional, reserves. Around 70% of all wells in the U.S. produce oil and gas at such low volumes that the income from the wells yields only a small margin of profit. These "stripper wells," while less desirable for an E&P C-corp’s portfolio, maintain steady production and are thus aptly suited for the more tax-efficient upstream MLP.
As large cap E&P C-corps routinely reinvest anywhere from 110% to 130% of their cash flow, these companies need a constant stream of capital. Upstream MLPs provide a practical market for proved acreage and enable access to the capital markets using an asset portfolio with an otherwise insignificant yield. E&P C-corps are able to maintain control (at least in the LP iteration) over the assets contributed to the MLP. The MLP, in turn, benefits from the steady supply of mature producing assets available for future drop-downs from the sponsor and has access to the sponsor’s institutional operational knowledge.
Another consequential boon to this MLP drop-down structure is that the two entities (the C-corp parent and the MLP) can bid in tandem on asset packages, with the MLP bidding on the more mature producing acreage in the asset portfolio and the C-corp bidding on the more risky undeveloped exploration acreage. Because of the MLP’s lower cost of capital, an upstream MLP can realize more value from an asset acquisition than a rival C-corp and can, in some instances, offer more competitive bids for the same acreage.
As large shale producers chase the seemingly never-ending opportunities arising from new resource plays, the pool of mature, low and steady decline assets will swell temporarily and the drop-down of this mature acreage into upstream MLPs could increase as an attractive way to monetize assets to fund producers’ expensive, capital-spending programs.