This section of the MLP University is intended for people who have worked through MLP 101 or people who already have a solid understanding of the MLP asset class. Our 201 section is designed to provide readers with a deeper understanding of the nuances behind the MLP business model and expand their knowledge beyond the basics offered in most MLP 101s.
The Creation and Definition of the Modern MLP
The modern MLP structure was created by an act of Congress. (See MLP 101: History of MLPs) Almost three decades ago, Congress passed the Tax Reform Act of 1986, signed by President Ronald Reagan on the South Lawn of the White House. In addition to eliminating a number of tax shelters, it defined the structure of the modern MLP. Congress limited the scope of MLPs via Section 7704(d) of the Internal Revenue Code, part of the Revenue Act of 1987. To maintain pass-through status and pay no entity-level tax, a publicly traded partnership must derive at least 90% of its income from qualifying sources. As it currently stands, Section 7704(d)(1)(e), the relevant section for energy MLPs, defines qualifying income as follows:
(A) interest, (B) dividends, (C) real property rents, (D) gain from the sale or other disposition of real property (including property described in section 1221(a)(1)), (E) income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy, and timber), or industrial source carbon dioxide, or the transportation or storage of any fuel described in subsection (b), (c), (d), or (e) of section 6426, or any alcohol fuel defined in section 6426(b)(4)(A) or any biodiesel fuel as defined in section 40A(d)(1), (F) any gain from the sale or disposition of a capital asset (or property described in section 1231(b)) held for the production of income described in any of the foregoing subparagraphs, and (G) in the case of a partnership described in the second sentence of section 7704(c)(3), income and gains from commodities (not described in section 1221(a)(1)) or futures, forwards, and options with respect to commodities. Section 7704(d)(4) provides that “qualifying income” also includes any income that would qualify under section 851(b)(2)(A) or section 856(c)(2).
Any pre-1986 MLP that had other kinds of income was given a grandfather clause and allowed to continue to use the structure, but most have gone private or converted to another structure.
The Evolution and Expansion of MLPs
If a company is thinking about forming an MLP or an existing MLP is wondering if a certain type of business would generate qualifying income, a private letter ruling may be requested from the IRS. When issued, private letter rulings (PLRs) are public documents that can provide insight into the reasoning of the IRS. A PLR cannot be used as precedent and applies only to the MLP requesting it. The IRS redacts the company’s name and some specifics from the PLR.
Natural resources were originally designated as oil, gas, petroleum products, coal, timber, and any other depletable natural resource defined in Section 613 of the federal tax code. In 2008, newly issued PLRs more broadly interpreted the definition of natural resources for the first time since 1987 to include limited alternative fuels businesses, specifically the transportation and storage of ethanol, biodiesel, and liquefied hydrogen. Since then, the scope of PLRs has broadened and the number issued has significantly increased.
In 2013, there were 29 PLRS issued, many of which covered businesses and products ancillary to the drilling process and traditional midstream activities. The IRS began interpreting the law to include assisting in the hydraulic fracturing process via fluids handling, waste treatment and disposal, and mining and processing of sand and ceramic proppants.
In 2017, following a review period by the IRS, new guiding regulations were issued detailing and clarifying what was originally spelled out in the tax code. Namely, that there is no exclusive list of activities, but extended processing and manufacturing are not included. The intention is that raw natural resources may only be refined into a traditionally saleable form, but that processing beyond that point (for instance, petrochemical manufacturing) is not a qualifying activity. PLRs will still be needed, but not likely to the same extent seen in 2013.
Shale is a type of geological formation found in sedimentary rocks. It can be hard to imagine what the rock beneath us looks like, however above-ground rock formations can provide excellent (and breathtaking) evidence of how the rocks in a particular area have developed. Imagine the layers seen in the image below, but on a larger scale, miles underground.
When the media refers to natural gas plays such as the Haynesville Shale in Northern Louisiana, or the Marcellus and Utica Shales in Ohio and Pennsylvania, they are referring to a specific layer of rock formed at a particular time in history. The amount and type of natural resources found in that layer will depend on what sort of life form, water, or lack of water existed during that period in time. Notice how the Marcellus formation sits above the Utica formation.
The map below shows some of the major natural gas, crude oil, and NGL plays in the United States.
Source: PacWest Consulting Partners, June 2016
For many decades, producers drilled for oil and gas in rock formations such as carbonates, sandstones, and siltstones. These formations, known as conventional formations, have multiple porous zones that allow the oil and gas to flow naturally through the rock. This ability of rocks to allow fluids to flow is known as permeability.
Conventional formations have higher permeability than unconventional formations like shale rock. Vertical drilling, which involves drilling a pipe straight into the ground, worked for many years on conventional formations because once the drill bit hit a particular area, the high permeability would allow for the hydrocarbons to be extracted easily. For quite some time, the energy industry has known that oil and gas existed in shale. But because shale rock is not as permeable, using old techniques with vertical drilling did not make it economically feasible to recover resources because it would only capture a limited amount.
Three technologies combined together truly changed the game for extracting shale resources:
- 3D seismic imaging
- horizontal drilling
- hydraulic fracturing
While seismic imaging in 3D may be the least well known component of the shale revolution, it is the primary driver of success rates. Seismic technology uses acoustic energy, vibrations, and reflected signals to determine the location and density of rock formations. Think of it like an underground map. While considerably more expensive than 2D seismic imaging, 3D seismic imaging results in fewer dry holes and more productive wells.
Horizontal drilling is another technology that has drastically improved the success rate and economic viability of shale drilling. Instead of drilling many vertical wells on the surface to fully explore a reservoir, horizontal drilling allows the operator to drill a single vertical well, and then manipulate the drill bit underground to cover a much larger area. Multiple horizontal wells can be maintained from a single drill pad, lowering construction costs and minimizing the impact to the environment.
After the well is drilled and lined with casing, a second technique called hydraulic fracturing is used, often in conjunction with horizontal drilling. Hydraulic fracturing describes the process in which a mixture of water, sand, and other chemicals is pumped into a well at a very high pressure to break up delicate shale rock. Think of a Butterfinger candy bar, but instead of candy and air, there are rocks and hydrocarbons. The highly pressurized mixture lets a driller open all those tiny pockets. The water is then removed, and the remaining sand props open the rock, allowing hydrocarbons to flow freely to the surface.
In short, 3D seismic drilling tells producers where to drill, horizontal drilling increases the amount of area drilled, and hydraulic fracturing solves the issue of low permeability.
The General Partner – Limited Partner Relationship
As explained in MLP 101, MLPs generally have two classes of owners, the general partner and limited partners. The GP controls the operations and typically owns a 2% equity interest along with incentive distribution rights (IDRs). A pure-play GP typically owns only the 2% interest in the MLP as well as IDRs; however, a GP is not prohibited from owning and operating assets or owning additional LP interests.
Just like a corporation may have thousands or millions of shareholders, MLPs also have thousands of unitholders. They provide capital to the company but have no role in the partnership’s operation or management. In traditional corporations, the management team and board of directors have a fiduciary duty to shareholders. However, MLP partnership agreements specifically state that no fiduciary duty is owed to unitholders and no unitholder vote is necessary to approve major changes, something for which MLPs have frequently received criticism. While unitholders may have no legal recourse on the grounds of fiduciary duty, the GP/LP structure is designed to align the interests of all parties. This is the basis for incentive distribution rights (IDRs), which will be explained later in more detail. Essentially, as the distribution to unitholders increases and surpasses target levels, the GP is also monetarily rewarded. For the LP unitholder, partnership agreements mandate that MLPs pay out nearly all available cash, providing significant current income. Additionally, minimum quarterly distributions (MQDs) are written into the partnership agreement.
In addition to the tax benefits, this two-tier structure is the reason many companies that generate qualifying income prefer the MLP structure. Both the GP and the LP can raise capital for projects, allowing for greater flexibility in financing. Additionally, a corporate sponsor may sell an integral asset to the MLP to realize the value of the asset while still maintaining control. Refining companies with daughter MLPs frequently do this with pipelines and storage facilities that supply and support the refining process. The LP unitholders benefit from the growth visibility provided by these drop downs.
Not all MLPs are structured as an LP with a GP. Some LPs have a GP but no IDRs, while others have no GP at all.
Publicly Traded MLP GPs
The number of public GPs waxes and wanes over the years. Originally, GPs were privately owned only by the MLP sponsor and management teams, but investors clamored to participate and private equity sponsors were looking for alternative exit strategies. For instance, from 2004-2006 there with 11 IPOs of MLP GPs, but following the financial crisis, yield spreads between LPs and GPs narrowed significantly. As financing became more expensive, LPs began to acquire their GPs, eliminating the IDR structure and lowering their cost of capital. Then, in 2010, the MLP GP IPO market reopened but this time, some GPs were structured or elected to be taxed as C corporations to remove the complication of a K-1 for investors. Later, following the commodity slump in 2014-2016, MLPs that still had a GP began to explore various ways to lower their cost of capital. In some cases, IDRs were bought in while the GP remaining trading. In other cases, the GP became a simple tracking stock for the LP. And in still others, reversing the trend, the GP bought in the LP, and the entire company became a C corporation.
As a result, there are now three basic types of publicly-traded MLP GPs:
- Formed and taxed as a partnership. Issues a K-1.
- Formed as a partnership but elects to be taxed as a corporation. Issues a 1099.
- Formed and taxed as a corporation. Issues a 1099.
Many investors want K-1s about as badly as they want bed bugs and some investors looking to own MLPs in a retirement account worry about UBIT. When GPs were considering their IPOs, they listened to these concerns and now many GPs are either structured as a corporation or taxed as one. This way, they can issue the familiar Form 1099 to investors at the end of each year. .
Finally, governance should also be considered. The partnership structure has looser governance requirements and may allow the general partner to retain the level of control that it desires after going public.
Incentive Distribution Rights (IDRs)
The general partner’s board of directors dictates the amount of the LP distribution. While the GP may benefit from MLP distribution increases through its LP stake, over the long term, the largest portion of its cash flow is derived from its ownership of IDRs. When a GP owns IDRs, it will increasingly benefit from successive distribution increases. Owning IDRs incentivizes the GP to grow the LP distributions by entitling GPs to receive a higher percentage (generally up to 50%) of incremental cash distributions when the distribution to LP unitholders reaches certain thresholds.
This works very similarly to income tax brackets in the United States. IDRs typically begin with the GP receiving 2% of the total cash flow, equal to its LP equity interest. When the distribution increases to the next tier, the GP will begin to receive a higher percentage of the cash flows above that point, say 15%. Typically, the highest tier is a 50/50 split of incremental cash flow. The cash received also increases when the number of LP units outstanding increases. While the GP technically has no legal fiduciary duty to the LP, there is an alignment of interests between GPs and LPs, in that both want to see LP distributions grow steadily over time. As the LP moves into the higher IDR splits, publicly traded GPs are often awarded premium valuations and have significantly lower yields than their corresponding MLPs.
Please see an extended example of IDR tiers here.
As mentioned above, should the MLP experience lower cash flows for a temporary period, the GP may forgo a certain portion of its cash flow from IDRs or its share of LP units. In this way, the GP is encouraged to grow the MLP sustainably.
An MLP with a GP and IDR structure can also have a higher cost of equity, as the return on an acquisition or project must compensate both the LP and the GP. For this reason, several MLPs have bought back the IDRs or merged with their GP to provide higher growth rates for their LP unitholders.
The Importance of Distributions
As mentioned in MLP 101, stable distributions have historically been a hallmark of the MLP space. MLP distributions are not guaranteed and depend on each partnership’s ability to generate adequate cash flow. Unlike Real Estate Investment Trusts (REITs) that must distribute a certain percentage of their cash flow each quarter in order to retain their tax-advantaged designations, MLPs have no such requirements. Like REITs, MLPs pay no taxes at the entity level, so they can distribute much more of their cash flow for investors.
Typically, the partnership agreements of individual MLPs determine how cash distributions will be made to GPs and LPs. Generally speaking, partnership agreements mandate that the MLP distribute all of its distributable cash flow (DCF), less a discretionary reserve determined by the GP, to unitholders within 45 days after the end of a quarter. Traditionally, MLP discretionary reserves are small, so MLP payout ratios are higher than those of C corporations, even Utilities.
Historically, MLPs have raised their distributions by 7.4% on an annualized basis. This predictability and growth has garnered MLPs premium valuations as compared to the broader equity market. When an MLP is going through financial difficulties, it can free up cash flow by reducing or eliminating its distribution. There are some other options for an MLP with a general partner. A GP can elect to give back or delay distributions on its subordinated units, it can forego IDRs for a period of time, or even forego distributions on its LP units.
Variable Distribution MLPs
While many investors have come to associate stable and growing distributions with MLPs in general, the mandate to maintain and grow the distribution is delineated in each individual partnership agreement. Within the past decade, some MLPs have gone public without a clause in the partnership agreement mandating conventional MQDs. These MLPs pay out 100% of cash flow, resulting in varying levels of distributions each quarter. Often, this is due to the business the MLP operates. The majority of variable distribution MLPs have business models that are directly exposed to commodity prices, which greatly affects the amount of DCF available to pay out to unitholders. For example, these businesses may be nitrogen fertilizer plants or refining facilities. Investors who prefer variable distribution MLPs often are interested in the expected total return or thematic play offered by these companies. Variable distribution MLP investors necessarily do not require the consistency that has historically been a hallmark of the MLP space.
Understanding MLP Cash Flows and Financial Reporting
An occasional criticism of MLPs is that they are a Ponzi scheme. For the most part, they are continually raising capital and continually increasing distributions, both hallmarks of a classic Ponzi scheme. However, in a Ponzi scheme, new money raised is paid to existing investors, and the whole effort depends on ever increasing numbers of new investors.
While MLPs do pay out the majority of their incoming cash flow to investors, they strive to retain an adequate amount of cash for day-to-day operations. However, in order to build new projects or acquire a new asset, they must continually return to the debt and equity markets for financing.
When the new asset comes online, the increased cash flows will then translate into increased distributions. This instills capital discipline into MLP management teams, as each time they access capital, they will be assessed on the success of their previous projects. In a worst case scenario where MLPs are unable to access the capital markets, the entire structure does not crash like a Ponzi scheme. As long as energy demand remains consistent, MLPs will continue to own stable assets that generate cash flow. The only difference is that their growth outlook is tempered. In other words, investors will receive income (yield) but lower growth (total return).
The other way this criticism appears is in regards to MLP income statements. When it comes to MLPs, investors, analysts, and management teams all look past the more common earnings metrics and focus instead on distributable cash flow (DCF). While earnings are still priceless for journalists, asset allocations, and top-down investing, they become markedly less useful when it comes to business models which require significant capital investment. To the unaware observer, a company that looks like it is distributing more cash than it is earning would be a very risky if not entirely foolhardy investment. However, earnings (as reported in quarterly statements) are standardized and determined by accountants, so there are often differences between an accountant’s earnings measures and the actual cash coming in the door. These accounting differences can make it seem like MLPs are engaged in dangerous business practices. The main culprit is non-cash depreciation contained in the Depreciation, Depletion, and Amortization (DD&A) accounting line item.
On the income statement, depreciation spreads the cost of an investment (such as a processing plant, pipeline, or even a truck) over its useful life. Accelerated depreciation, used by most MLPs, allows greater deductions in the early years of an asset’s life. However, neither of these represents an actual cash outflow. Depreciation can be very high for MLPs as many grow organically by continuously laying miles of pipe in the ground and adding additional storage tanks and compressor stations. Once in service, however, these assets immediately begin generating cash flows with minimal maintenance expenses. Most MLP investors prefer to focus on these actual cash flows rather than earnings metrics that don’t affect the distribution.
Similar to how REITs define their cash flow from operations as funds from operations (FFO), MLPs use DCF as the primary measure of cash available to distribute to unitholders or to fund growth. DCF is considered a non-GAAP
financial measure. Investors should understand that the definition and calculation of DCF may vary among partnerships, as ultimately, each MLP determines its definition of DCF in its partnership agreement. Unfortunately, there is no standard measure or definition of DCF. This means that the Financial Accounting Standards Board (FASB), the body for setting accounting standards, has not outlined a standard definition and calculation for DCF. The calculation of DCF is typically the following:
DCF = net income (+) depreciation, depletion, and amortization (-) cash interest expense (-) maintenance capital expenditures (+/-) other non-cash items.
Net income, often referred to as the “bottom line,” is a standardized measure of performance implemented by the FASB. DD&A includes the non-cash depreciation mentioned earlier and is removed from the cash calculation. Cash interest expense, however, is a very real cash outlay. Maintenance capital expenditures, those costs required to maintain the operating capacity or revenues of an existing asset, are also included as these are regular cash expenses necessary to sustain the business. Other miscellaneous non-cash expenses (such as unrealized gains or losses on hedges) are reversed.
All in, as MLPs are continually investing in new assets, they are frequently taking advantage of accelerated depreciation accounting rules. Deducting non-cash depreciation in the calculation of earnings can create the illusion that MLPs are distributing more than they earn, something which can startle and dismay an inexperienced MLP investor. As such, earnings per unit is not a useful measure when examining the financial health of a growing MLP.
Tax Efficiency and Accounting with MLP Investing
As mentioned previously, MLPs pay no taxes at the entity level if 90% or more of their income is from qualifying sources. Due to the tax efficiency of the structure, MLPs have a lower cost of capital as compared to traditional C corporations. The pass-through nature of a partnership means the items on an MLP’s income statement flow through and are proportionately allocated to the end investor.
To explain in further detail, a unitholder’s cost basis is adjusted upward by the amount of partnership income allocated to that unitholder and adjusted downward by the amount of cash distributions (or actual payments) received. For most MLPs, cash distributions exceed allocated income, and the difference between distributed cash and allocated income is treated as “return of capital” to the unitholder and reduces the unitholder’s basis in the units. Typically, 70%-100% of MLP distributions are considered tax-deferred return of capital, with the remaining portion taxed at ordinary income rates in the current year.
As long as the investor’s adjusted basis remains above zero, taxes on the return of capital portion of the distribution are deferred until sale of units. If an investor’s basis reaches zero, then future cash distributions will be taxed as capital gains in the current year. Upon sale of the MLP, the gain resulting from basis reductions is recaptured and taxed at ordinary income rates and any remaining gain is taxed at capital gain rates for investments held greater than one year.
An MLP’s tax pass-through status applies at both a federal and a state level. An MLP unitholder is responsible for paying state income taxes on the portion of income allocated to the unitholder for each individual state in which the MLP operates. For companies that have networks of pipelines reaching across America, this can mean a considerable number of additional filings for the investor. In most cases, however, unless the unitholder owns a large position, the share of allocated income is small and the unitholder may not have to file in some states due to minimum income limits. Additionally, some states, such as Texas and Wyoming, do not have state income taxes.
If an investor is looking to own an MLP in a tax-advantaged account such as an IRA, partnership income (not cash distributions) may be considered unrelated business taxable income (UBTI) and subject to unrelated business income tax (UBIT), if UBTI exceeds $1,000 in a year. The custodian of the IRA is responsible for filing IRS Form 990T and paying the taxes.
From an estate planning perspective, if units are passed along to heirs, upon death of the unitholder, the basis is “stepped up” to the fair market value of units on the date of death and the gain resulting from basis reductions is not taxed.
MLP Business Models
Production & Mining – Traditional upstream, or exploration and production, companies focus on finding and drilling wells in new locations. Thanks to the development of technologies such as 3D seismic imaging, horizontal drilling, and hydraulic fracturing, the United States has experienced an overwhelming surge in hydrocarbon production.
Upstream – Upstream MLPs focus on acquiring assets that are already proven and producing oil or natural gas. They will often target older wells that have predictable decline curves and long reserve lives. However, the natural decline curve, over time, will reduce the cash flows to investors unless the MLP drills new wells or acquires new assets. Occasionally, Upstream MLPs will use techniques such as water flooding to increase the output of a well. These businesses can be more sensitive to commodity prices, although many will use hedging contracts to lock in current prices and reduce their exposure. This also provides better income visibility to investors.
Gathering & Processing – Before the hydrocarbons enter either a mainline or trunkline, they need to be gathered and processed. Gathering refers to the process of connecting wells to major pipelines through a series of small diameter pipelines, and processing is the removal of potential contaminants (including NGLs, which may actually be quite valuable) so that the gas can meet purity standards for pipeline transmission.
Gathering and processing MLPs focus on obtaining fee-based revenues by charging upstream companies a set fee for every cubic foot of natural gas or barrel of oil that is gathered or processed. The contract often includes a minimum volume commitment or acreage dedication, which provides further stability to the MLP. Occasionally, some MLPs will have different compensation structures, which may include payment in the form of keep-whole contracts, which allow the MLPs to keep the extracted NGLs and sell them to third parties at market prices. Another contract structure is percent of proceeds (colloquially known as POP), in which the processor is paid by retaining a percentage of any processed natural gas or NGLs. As keep-whole and percent of proceeds contract structures expose the MLP to volatility in commodity prices, the vast majority of MLPs have moved (or attempted to move) their compensation structure to purely fee-based.
Fractionation – At a fractionation facility, NGLs are separated into their individual usable components of ethane, propane, butane, isobutene, and natural gasoline. Ethane is primarily used as a feedstock, or input, into petrochemical plants to make ethylene, which is used to make plastics (primarily plastic bags) and other chemical products (such as solvents and adhesives). Propane by itself can be used as a heating fuel or used as a feedstock to make propylene, which can be used in the manufacturing of textiles or plastics (such as headlights, eyeglasses, foam bedding, and water bottles). In general, ethane and propane make up the bulk of the NGL stream, ranging from 55%-85%. Butane, isobutane, and natural gasoline are used to produce motor gasoline. Butane is the primary component of lighter fluid and can be used as a feedstock to make butadiene, which is used in creating synthetic rubber.
The majority of fractionation is done on a fee-for-service basis. However, the amount of fees earned depends on the amount of volumes fractionated, which in turn depends on something called the frac spread. Essentially, the frac spread is a measure of the reverse of the adage, the whole is greater than the sum of its parts. With NGLs, the sum of the parts is worth more than the whole. Some NGLs must be removed for the natural gas stream to meet purity standards, but often they are only removed for additional profitability. The frac spread is the difference between the value of the NGLs if removed, and the value of the NGLs if they are left in the natural gas stream and sold at the same price as the natural gas. Ethane rejection is the industry term for when ethane prices are so low that is more worthwhile to leave it in the natural gas stream than to extract it for sale as a petrochemical feedstock.
The high cost of NGL handling, storage, and transportation additionally factors into the volumes of NGLs that will be fractionated. In order for the hydrocarbons to remain liquids, they must be kept under high pressure or cooled to very low temperatures. Additionally, any gaseous NGLs are heavier than air and flammable, requiring increased safety measures. NGL storage typically takes place in underground caverns for these reasons, but the smaller amounts stored above ground require insulated tanks and thicker steel.
Transportation – Transportation MLPs are the bread and butter of the sector. The toll-road business model is the most well-known and most frequently referenced, perhaps because it is one of the simplest to understand. Interstate liquids pipelines earn money on a Price x Volume model. On the price side, these FERC-regulated pipelines increase the tariff they charge by PPI + 1.23 every July 1. The volume part of the equation is dependent on America’s use of energy. Decreases due to energy efficiency standards are matched and exceeded by increases due to population growth.
Interstate natural gas pipelines operate a different fee-based business model. Customers contract for these pipelines in much the same way that apartments are rented, but instead of year-long leases, interstate natural gas pipeline contracts are often for 5 to 20 years. Like a lease, customers are obligated to pay regardless of whether they use the space or not. Additional fees are charged when a customer needs to inject or withdraw hydrocarbons to meet demand spikes or oversupply. Think of it as if the apartment building had mandatory valet parking for a set fee each time. The length and terms of these contracts allow the pipeline company to earn the IRR necessary to break ground on new construction. MLPs have historically avoided building speculative projects, given the capital intensity of pipelines in particular. Building “on spec” would not be consistent with the intention of MLPs to pay consistent and growing distributions.
Marine transportation MLPs own tankers and carriers of crude oil, refined petroleum products, and liquefied natural gas. They may travel via rivers within the US or across oceans. As marine transportation contracts are relatively short-term in comparison to pipeline contracts, the business tends to be more sensitive to moves in commodity prices.
Storage –Natural gas that is not immediately required for electricity generation or heating is stored until needed. The same is true of crude oil waiting to be refined and refined products (such as gasoline, diesel, and jet fuel) waiting to be consumed. Storage facilities operate a fee-based business model similar to interstate natural gas pipelines, with contract lengths generally ranging from one to five years. Storage tanks for crude oil and refined products may also have inflation escalators.
MLPs are not involved in retail sales of energy; MLPs typically do not own gas stations, electricity generation, or local utility companies. However, under Section 7704, MLPs may lease out real estate to gas stations and supply them with fuel, although they may not own or operate them.
Natural Gas Pipelines
According to the Natural Gas Act, companies that would like to build an interstate natural gas pipeline must obtain a “Certificate of Public Convenience and Necessity” from the Federal Energy Regulatory Commission (FERC) before beginning a project. This is a multi-step process.
- Pre-Filing and Environmental Review. Pre-filing involves notifying all stakeholders of the proposed project and offering a medium for said stakeholders to voice concerns related to the project. This phase also includes a study of the potential project site. This process begins about seven to eight months before the application for the actual certificate is filed.
- Application for FERC Certificate. This is the beginning of the formal process. Applicants must turn in lots of data on the project, such as construction plans, route maps, schedules, and more.
- Environmental Review. An official study is carried out on how the project will impact the environment. The public is then given an opportunity to comment on the results of the study. After this, the FERC will consider the comments and issue formal approval or denial of the project.
The formal process takes about a year. However, this timeline is not yet guaranteed. A bill was passed in the House in 2015 that would require the FERC to complete the process in 12 months. The bill is currently being considered by the Senate.
The permitting of oil pipelines is not subject to FERC regulation. While companies constructing oil pipelines are required to obtain federal permits such as those described under the Clean Water and Clean Air Acts, state approvals are the only governmental authorizations required for oil pipeline construction projects to move forward. At first blush, this may seem like an advantage for oil pipelines, and it’s true that it could be a less cumbersome process depending on the pipeline’s path. Many would agree it’s easier to acquire permits to build a pipeline from Texas to Oklahoma than from Pennsylvania to New York, for example. However, dealing with landowner issues in multiple states isn’t easy. If a landowner doesn’t agree to the path of a pipeline and eminent domain authority does not exist in that landowner’s state, then the oil pipeline could be forced to take an expensive re-route. This is one of the primary advantages parties seeking to build natural gas pipelines have over those building oil pipelines, FERC approval includes federal eminent domain.
In the United States, interstate liquids pipelines are regulated by the Federal Energy Regulatory Committee (FERC). Unlike the antagonistic relationship most utilities have with their regulators regarding pricing, the FERC focuses on the safe and efficient transportation of energy throughout America. The FERC mandates that tariffs on all interstate liquids pipelines increase by PPI + 1.23% every July 1. This methodology will be in place until 2020, as the FERC reviews the PPI escalator every five years.
For interstate natural gas pipelines, the FERC enforces the Natural Gas Act, which mandates that the rates charged must be “just and reasonable”. This is determined by calculating the pipeline company’s cost of service, plus a return on their investment.
Intrastate pipelines are regulated by the states themselves. The most famous state regulatory agency is The Railroad Commission of Texas (a legacy name that may be changed in the coming years). Again, regulatory agencies typically work with MLPs to maintain standards of safety and maintenance.
Headquartered in Calgary, Alberta, the National Energy Board (NEB) regulates the interprovincial oil, gas, and utilities industries in Canada. It does not create energy policy; it merely regulates construction, operation, and tariffs, and includes the energy-related functions that the EPA would provide in the United States.
While there is no FERC-equivalent escalator in Canada, the NEB regulates tariffs in such a way as to ensure the company can recover its initial investment and earn a reasonable return while also maintaining and expanding the pipeline systems. Canadian pipeline companies may only charge a toll that has first been approved by the NEB. This process typically includes review and negotiation of the terms and conditions of pipeline access and the responsibilities of both parties.
Until the mid-1990s, all toll regulation was based on a cost-of-service model, but as that process is costly, time-consuming, and often belligerent and adversarial, alternatives are being developed. Some of these include a uniform rate of return (based on the interest rate of Canadian bonds plus a risk premium) as well as multi-year negotiated settlements between the shippers and the pipeline companies. In the case of negotiated settlements, the NEB still has final authority on the approval process. Less often, an incentive regulation will be used so that both parties share in the benefits of improved performance. Smaller diameter pipelines are subject to a more relaxed, complaint-based system. Tolls can be fixed or market-driven—there is no standard method.
The most common valuation metrics for MLPs are price to distributable cash flow (P/DCF), enterprise value to EBITDA (EV/EBITDA), yield spread to the 10-year Treasury, and the dividend discount model. Generally, price to earnings (P/E) is not used. MLPs invest so heavily in hard assets that depreciation accounting can occasionally make their earnings appear negative, while their cash flows continue to be stable and growing. For this reason, a multi-stage DCF discount model is preferred over all others. Since DCF is a measure of the cash flow available to be paid out to investors every quarter, it is a much more accurate reflection of the health and sustainability of an MLP.