A beginner's guide to MLPs
The nuances of MLP investing
- The Creation and Definition of the Modern MLP
- The Evolution and Expansion of MLPs
- Shale Revolution
- The General Partner – Limited Partner Relationship
- Incentive Distribution Rights (IDRs)
- MLP Consolidation into Corporations
- MLP Financing Evolves with Equity Self-Funding
- Understanding MLP Financial Metrics
- Tax Efficiency and Accounting with MLP Investing
- MLP Business Models
- Pipeline Permitting
- Pipeline Regulation
MLP investment options
- MLPs in Your Portfolio
- Buying Individual MLPs
- The Myriad of MLP Investment Products
- 40 Act Funds – C corporation taxation – 100% MLPs
- 40 Act Funds – RIC Compliant – Less than 25% MLPs
- Exchange-Traded Notes (ETNs)
- Separately Managed Accounts (SMA)
- Active Versus Passive
- Choosing an Active Manager
- Choosing an Indexed Product
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 space. 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.
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. 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. When the media refers to natural gas plays such as the Marcellus and Utica shales in Pennsylvania and Ohio, 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. 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.
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 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 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 plays a vital role when it comes to drilling a successful well. 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 rates and economic viability of shale drilling. Horizontal drilling allows the operator to drill a well, and then manipulate the drill bit underground to make a 90-degree turn and cover a much larger area. Multiple (up to 20 or more) horizontal wells can be drilled from a single drill pad, lowering drilling costs, increasing efficiency, and minimizing the impact to the environment. After the well is drilled and lined with casing, a second technique called hydraulic fracturing is used.
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 shale rock. 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
MLPs historically have had two classes of owners, the general partner and limited partners. The GP controlled the operations and typically owned a 2% equity interest along with incentive distribution rights (IDRs), which will be explained later in more detail. As the space has evolved, most MLPs have eliminated their IDRs, and their GP interest has become a non-economic interest. Other MLPs have no GP at all.
Just like a corporation may have thousands of shareholders, MLPs also have thousands of unitholders. They provide capital to the company but have no role in the partnership’s operations 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 was designed to align the interests of all parties. The desire to align the GP and LP was the basis for IDRs. Essentially, as the distribution to unitholders increased and surpassed target levels, the GP was also monetarily rewarded.
While the GP/LP structure and IDRs were intended to align interests and incentivize distribution growth, IDRs can become a burden as an MLP matures. Accordingly, we have seen most MLPs buy out their IDRs by issuing LP units or through other transactions.
Incentive Distribution Rights (IDRs)
The general partner’s board of directors dictates the amount of the LP distribution. 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.
Please see an extended example of IDR tiers here.
As the LP moves into the higher IDR splits, IDRs can become a burden to the cost of equity. An MLP with a GP and IDR structure can have a higher cost of equity, and the return on an acquisition or project must compensate both the LP and the GP. For this reason, most MLPs have bought back their IDRs. The reasons cited for these transactions include lowering the company’s cost of capital, increasing financial flexibility, and simplifying and aligning corporate structure. Additionally, the investment community has expressed frustration with IDRs, so MLP management teams will likely continue to pursue IDR eliminations.
MLP Consolidation into Corporations
As discussed above, IDRs can become a burden to MLPs over time by increasing the cost of equity, which increases the required return on an acquisition or project. As a result, a high cost of equity can harm the long-term sustainability of the partnership and make it less competitive when it comes to pursuing projects. While some MLPs have bought out their IDRs to address this issue, others have been involved in reorganization transactions to simplify corporate structure and lower the cost of capital. In some cases, the GP has acquired its MLP; while in other cases, the MLP has bought out its GP.
In a landmark transaction for the MLP and energy infrastructure space, Kinder Morgan reorganized in 2014 by consolidating two publicly-traded MLPs and an LLC into one corporation and simultaneously eliminated IDRs. From 2015-2017, a few other MLPs were acquired by their C-Corporation parents, but consolidation of MLPs by C-Corporation parents accelerated in 2018 for a variety of reasons, including depressed equity valuations, the FERC policy revision (read more), the desire to simplify structure (eliminate IDRs) , and tax law changes. The wave of consolidation announcements seen in 2018 slowed in 2019 and is not expected to continue in 2020 (read more).
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Stable distributions were historically a hallmark of the MLP space, though the energy downturn that began in the second half of 2014 has blemished that track record. When an MLP is going through financial difficulties, it can free up cash flow by reducing or eliminating its distribution. While some MLPs continued to grow their distribution through the downturn, other MLPs cut their distributions. 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 to investors. Typically, the partnership agreements of individual MLPs determine how cash distributions will be made to GPs and LPs.
MLP Financing Evolves with Equity Self-Funding
In the past, MLPs would often rely on equity markets for funding growth capital. In order to build new projects or acquire a new asset, they would issue debt and equity for financing. Because equity capital markets were depressed following the oil downturn of 2014-16, issuing equity for MLPs became expensive (yields were high) and difficult (lack of appetite from investors). As a result, MLPs are increasingly shifting towards self-funding the equity portion of their growth capital using retained cash flows. The shift to equity self-funding is positive for MLP investors as equity dilution subsides, and MLP management teams are forced to exercise greater capital discipline.
Understanding MLP Financial Metrics
MLP financial metrics can be nuanced relative to other sectors. For example, 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). 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. 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 Financial Accounting Standards Board (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 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.
For MLPs, earnings metrics become markedly less useful when it comes to business models which require significant capital investment. Earnings (as reported in quarterly statements) are standardized and subject to accounting rules, so there are often differences between reported earnings and the actual cash flow generated. 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 or pipeline) 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 building energy infrastructure. 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.
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. As such, earnings per unit often has limited usefulness for MLPs.
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 this 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. Notably, the passage of the Tax Cuts and Jobs Act in 2017 allows taxpayers to receive a deduction of 20% on qualified business income (QBI) from publicly traded pass-through partnerships, which include MLPs. For example, if 80% of a distribution is considered tax-deferred return of capital, then the remaining 20% will be taxed as ordinary income with the 20% QBI deduction. This deduction also applies to 20% of income that is recaptured when units are sold.
As long as the investor’s adjusted basis remains above zero, taxes on the return of capital portion of the distribution are deferred until the units are sold. If an investor’s basis reaches zero, then future cash distributions will be taxed as capital gains in the current year. At the time units are sold, the gain that results from basis reductions is taxed as ordinary income with a 20% deduction, while the remaining amount is taxed as a capital gain. For more information, please see this note.
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 the US, 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
In MLP 101, the pipeline business was thoroughly examined and explained. Pipelines are perhaps the most familiar of the assets that midstream MLPs operate, but these companies are also involved in a much larger swath of the energy value chain.
Gathering & Processing – Before hydrocarbons enter a large pipeline, they need to be gathered and, in the case of natural gas, processed. Gathering involves connecting wells to major pipelines through a series of small diameter pipelines. Gathering pipelines transport either crude oil or natural gas from the wellhead. Processing is required for natural gas and involves the removal of potential contaminants and separation of natural gas liquids (NGLs) so that the gas can meet purity standards for pipeline transmission.
Gathering and processing companies focus on obtaining fee-based revenues by charging upstream companies a set fee for every million British Thermal Unit (MMBtu) 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 cash flow stability. Occasionally, some MLPs will have different compensation structures, which may include payment in the form of keep-whole contracts. This allows them 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 POP contract structures expose gathering and processing companies to volatility in commodity prices, the vast majority of companies have moved (or attempted to move) to a purely fee-based revenue structure.
Fractionation – At a fractionation facility, NGLs are separated into their individual usable components of ethane, propane, butane, isobutane, and natural gasoline. Ethane is primarily used as a feedstock, or input, into petrochemical plants to make ethylene, which is used to make plastics 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, with a concentration ranging from 55% to 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 natural gas. Ethane rejection is the industry term for when ethane prices are so low that it is better to leave ethane in the natural gas stream than extract it.
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, gaseous NGLs are heavier than air and flammable, requiring increased safety measures. NGL storage typically takes place in underground caverns for these reasons, while the smaller amounts stored above ground are placed in insulated tanks and thicker steel.
Transportation – Transportation companies are the bread and butter of the sector. The fee-based business model is the most well-known and most frequently referenced, perhaps because it is one of the simplest to understand. Typically, midstream companies will enter long-term contracts with customers committing to use a certain amount of pipeline capacity. The midstream company will collect a fee per unit of hydrocarbon transported. Contract provisions such as take-or-pay agreements or minimum volume commitments allow the pipeline company to collect specified fees even if the customer does not fully use its committed capacity.
Interstate liquids pipelines are regulated by the Federal Energy Regulatory Commission (FERC), and rates are most often based on the FERC’s oil pipeline index. Every five years, the FERC sets the rate by which tariffs will be increased, with the rate based on the Producer Price Index for Finished Goods plus an adjustment. Through 2021, these FERC-regulated pipelines will increase the tariff they charge by PPI + 1.23% every July 1.
Interstate natural gas pipelines generate revenue by collecting a tariff for each unit of natural gas transported under long-term commitments. Customers enter contracts for capacity 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. The length and terms of these contracts allow the pipeline company to earn the rate of return necessary to break ground on new construction. Transportation companies have historically avoided building speculative projects (“on spec”), given the capital intensity of pipelines in particular. Instead, pipeline companies will move forward with projects once they have sufficient customer commitments.
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 rent, with contract lengths generally ranging from one to five years. Storage tanks for crude oil and refined products may also have inflation escalators.
Production & Mining (less common) – These MLPs typically 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, these 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 prices and reduce their exposure. This also provides better income visibility to investors.
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 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 guaranteed. In April 2018, FERC requested stakeholder input on its current policies to review and authorize interstate natural gas pipelines, particularly related to the transparency, timing, and predictability of its certification process. As of March 2019, there have been no updates.
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. Many would agree it is easier to acquire permits to build a pipeline from Oklahoma to Texas than from Pennsylvania to New York, for example. However, dealing with landowner issues in multiple states is not necessarily easy. If a landowner does not 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 a more expensive alternative route. For natural gas pipelines, FERC approval includes federal eminent domain – a primary advantage of building a natural gas pipeline over building an oil pipeline.
In the United States, interstate liquids pipelines are regulated by the Federal Energy Regulatory Commission (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 + 0.78% every July 1. This methodology will be in place until 2026, 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 its investment.
Intrastate pipelines are regulated by the states themselves. The most famous state regulatory agency is The Railroad Commission of Texas (a legacy name). State regulatory agencies work with pipeline companies to maintain standards of safety and maintenance.
Headquartered in Calgary, Alberta, the Canada Energy Regulator (CER) regulates the interprovincial oil, natural 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.
Similar to the FERC, the CER regulates pipeline tariffs to ensure that the rates are just and reasonable. The NEB establishes tariffs in a way to allow companies to cover their costs and earn a reasonable return for its investors. Canadian pipeline companies may only charge a toll that has first been approved by the CER. This process typically includes review and negotiation of the terms and conditions of pipeline access and the responsibilities of both parties. Tariffs are often based on cost-of-service regulation. As a result, lower throughput can lead to greater tariffs as costs are shared by fewer shippers, or an expansion of a pipeline could lead to higher or lower tariffs depending on the change to throughput and revenue. Aside from cost-of-service regulation, pipelines may also operate under negotiated settlements with the pipeline company and its customers reaching an agreement on tariffs and operational matters, which is then approved by the CER. Most of the major CER-regulated pipelines have operated under negotiated settlements in recent years. For a further overview of pipeline regulation in Canada, see the CER website here.
Valuation metrics for MLPs have historically been based on yield or distributable cash flow, as well as enterprise value to EBITDA (EV/EBITDA). Common metrics included price to distributable cash flow (P/DCF), yield spread to the 10-year Treasury, and the dividend discount model. Valuation methods for MLPs are evolving as the midstream business model and investor base also evolves (read more). EV/EBITDA and free cash flow yield, which allow for comparability across sectors, are likely to gain more traction going forward. Price-to-earnings ratios may also be used to value midstream companies, but P/E ratios can sometimes be distorted by the high depreciation expense for MLPs, which may make earnings appear minimal or negative when in reality their cash flows remain stable and growing.