Discounted Cash Flow Valuation for Oil and Gas Pipelines

By Eric C. Henson, Vice President, Compass Lexecon

Discounted cash flow (DCF) analysis is a standard method for valuing a wide range of assets such as fixed assets, including oil and gas pipelines, as well as stocks, bonds and real estate investments/properties.

Typically, assets in any financial analysis produce a series of cash flows. DCF analysis values this series of cash flows by bringing them to the present. That is, DCF analysis finds the present value of expected future cash flows that will be derived from the assets in question. In simple terms, DCF analysis determines the value of assets today based on projections of all of the cash that is expected to come from the assets in the future.

The term “discounted” in DCF analysis arises from the principle of the time value of money. This is the idea that money today is worth more than the same amount of money in the future.

This holds, in part, because money today can be invested to earn interest over time. Because of the time value of money, DCF analysis requires that future cash flows be converted to current cash flows using an appropriate discount rate. Thus, future cash flows are multiplied by an appropriate discount factor for each period to calculate the net present value of these future cash flows – that is, the amount that an investor would expect to receive in the marketplace at a particular time for the rights to receive such cash flows, given the perceived risk of the enterprise and the time value of money.

Discounting reflects the reality that a dollar received sometime in the future is worth less to an owner or investor than a dollar received now. This reality is seen in the fact that the market compensates investors (including lenders) by paying them interest for giving up dollars today in exchange for the prospect of receiving a greater number of dollars in the future.

In simplified terms, there are three steps in valuing an asset by way of DCF analysis. The first step in DCF analysis is to project the estimated free cash flow that can be derived from the asset. Free cash flow is fundamentally defined as net cash arising from operating activities less capital and operational expenditures. The second step in DCF analysis is to estimate the appropriate discount rate for the asset in question.

This discount rate accounts for the time value of money, with cash in the future being worth less than cash today, and should also account for the risk that is inherent in the asset. Applying the correct discount rate to the projected free cash flows that can be generated by the asset brings those future values back to a net present value (NPV). The “net” indicates that this value is revenues less expenses, and the “present” indicates that this value is discounted to the current time period.

The third step in DCF analysis is usually determination of a terminal value. This terminal value is defined as the value of an asset at the end of a specified time period, often ending five or ten years from the time of valuation, and is typically associated with the final projection/estimation of free cash flows.

Oil and gas pipelines are excellent examples of fixed assets that lend themselves to valuation by DCF analysis. Application of the steps noted here to any particular pipeline is done by: First, estimating the pipeline’s future free cash flows (i.e., operating revenues minus capital and operational expenditures); second, applying the appropriate discount rate to the projected free cash flows; and third, determination of a terminal value for use at the end of projected free cash flows.

Key Inputs 

Undertaking a DCF analysis for an oil or gas pipeline will necessarily entail incorporation of a series of assumptions and projections. These assumptions and projections will often include:

Pipeline use: The volume transported through a pipeline system, known as “throughput,” is a critical metric in determining the cash flows resulting from the pipeline’s operation.

While a pipeline is built to transport a certain maximum volume, it is not necessarily reasonable to assume that the pipeline will be utilized at or even near capacity for its entire economic life. A combination of economic and environmental factors, such as competing transportation systems to major pricing hubs or declining production in the area near the pipeline’s origination point, can lead to lower throughput.

Given that revenue equals price times quantity, varying the projection for the quantity of oil or gas transported by a pipeline (i.e., varying the throughput) will, in turn, vary the projected revenue generated by the pipeline. It is clear that a pipeline that is full generates more revenue than one that is operating less full, all else being equal.

For example, in recent times the Trans Alaska Pipeline System (TAPS), one of the world’s largest pipeline systems, has been struggling with declining throughput. At its peak flow in the 1980s, the pipeline transported 2 MMbpd.

However, throughput on TAPS consistently declined between 1-15% per year from 2002-15. Average daily throughput for 2016 was about 518,000 bpd, lower than the average daily throughput when the pipeline was first put in operation in 1977. Once transporting near full capacity, the pipeline operates at less than a quarter of its design capacity of about 2.14 MMbpd.

Pipeline tariffs: Another important factor in pipeline valuation is the expected revenue per unit transported through the system, which directly affects the projected cash flows a pipeline is expected to generate. Pipelines earn revenue by charging shippers fees, known as “toll rates” or “tariffs,” for the right to transport along their infrastructure; these tariffs can vary over time due to several factors such as changes in throughput, operating and capital costs, and market conditions. It is important to note that changes in tariffs often have to be approved by the government before they can be implemented.

For example, if a pipeline company undertakes construction of new facilities or expands existing infrastructure, it may seek to raise its tariffs in order to cover its costs of capital investment. Companies may also increase tariffs due to declines in the volume of firm contracts or throughput.

To maintain constant revenues in the event of lower throughput, the company must increase its prices to compensate for the decreased volume. Conversely, tariffs may decrease in times of competitive market conditions. For example, a new pipeline system with similar routes and connections to existing infrastructure can threaten the throughput on the existing pipelines by offering an alternative transportation option.

If any of these factors can be reasonably foreseen, particularly upcoming construction of competing projects, it is important to account for their potential effect on the tariff chosen for valuation purposes.

Consider the tariff for light petroleum transportation on the segment of Enbridge’s Canadian Mainline between the Edmonton Terminal in Alberta and the international border near Gretna, Manitoba. Between 2010 and 2015, Enbridge’s tariff increased by almost 70%, rising from approximately C$12 per cubic meter to C$20 per cubic meter.

Tariff increases over this five-year span were spurred by costs associated with Enbridge’s Alberta Clipper Pipeline as well as an additional transportation surcharge resulting from the company’s Edmonton-to-Hardisty Pipeline project.

Pipeline tariffs can also move in the opposite direction, as seen with TransCanada’s recent long-term, fixed-price tariff for transporting natural gas on the Mainline between Empress, Alberta and the Dawn hub in southern Ontario (a major storage hub serving the Great Lakes and Eastern Canada).

TransCanada has been facing increasing pressure to protect its share in the Ontario market, which has been threatened by growing Marcellus and Utica natural gas production and the potential for competing U.S. pipelines such as Energy Transfer Partners’ Rover and DTE Energy/Spectra (Enbridge) Energy’s Nexus) to bring northeastern U.S. gas production to the Dawn hub.

To entice Western Canadian producers to use its Mainline, TransCanada has offered discounted tariffs of C$0.77 per gigajoule to producers who agree to contracts requiring shipment of 1.5 petajoules of natural gas per day for 10 years, beginning in November 2017. This tariff presents a discount of nearly 50% from the company’s usual firm transportation tariff of C$1.42 per gigajoule between Empress and the Dawn hub.

Terminal value: At the end of the valuation timeframe (usually after a five- or ten-year time horizon for which projected cash flows are generated in the normal course of business by the pipeline owner/operator), the pipeline will have an additional monetary value, reflecting expectations for cash flows in the future. The terminal value is commonly derived using what is known as the “Gordon Growth Model,” which is used for valuing assets that are expected to have stable growth in their cash flows after the valuation timeframe.

Projecting a terminal value in DCF analysis allows for the inclusion of future cash flows beyond the forecast period, which implicitly values the pipeline in perpetuity by extending the model’s volume, revenue, and growth assumptions. The discounted terminal value thus derived is then added to the discounted cash flows in order to calculate the NPV of the pipeline.

Although use of a terminal value is common, it is important to note that this technique can lead to misleading results and overvaluation because pipelines have finite economically useful lives, which are determined by both physical depreciation as well as changing market conditions.

The large-scale decommissioning of several assets underway in the North Sea illustrates the nature of the implied perpetual cash flows inherent in inclusion of a terminal value in modeling. Once a crucial source of large volumes of crude oil for the world market, the North Sea now contains several fields nearing exhaustion.

For example, the Brent field in the North Sea, the eponym for the worldwide oil benchmark Brent Crude, is nearing the end of its economically useful life after 40 years of production. Exhausted oil fields, high costs that discourage new exploration in the area, and low oil prices have resulted in many operators preparing assets for decommissioning. It is estimated that by 2025, 847 pipelines spanning about 7,500 km will be decommissioned in the North Sea.

In-Service Date: As the timing and size of cash flows are crucial to DCF analysis, a key input when valuing a pipeline that is not yet completed is the operational start date, which is known as the “in-service” date. Before the initial date of operation, costs will be incurred, but revenues will not yet be generated, and this negative cash flow will persist until operations are underway.

For pipelines transporting hundreds of thousands of barrels of oil, or billions of cubic feet of natural gas daily, in-service delays of even one year can have a significant downward impact on the pipeline valuation due to the magnitude of those lost cash flows. To avoid overvaluation, it is crucial to avoid an artificially early start date and to account for potential delays, which will both result in unrealistic and inflated expectations of initial incoming revenues.

Many factors can delay the expected in-service date for a pipeline, such as regulatory approvals, opposition by opposed political groups, drawn-out environmental studies, and construction delays. Due to the array of factors that can delay initial operation, it is not uncommon for pipelines to revise their originally projected in-service dates.

For example, two of Williams Partners’ natural gas pipelines have recently had to revise their in-service dates. The Atlantic Sunrise Expansion, designed to alleviate infrastructure bottlenecks in Pennsylvania by increasing deliveries on the Transco pipeline system by 1.7 Bcf/d, was expected to be operational in the second half of 2017 when Williams filed its certificate application with FERC in early 2015.

On Oct. 28, 2016 the expected in-service date for the project was revised to mid-2018 due to changes in scheduling of environmental review by FERC. This minor delay, of only six months, translates to over 300 Bcf of delayed/forfeited natural gas deliveries for the Atlantic Sunrise. Similarly, the Constitution Pipeline, a 124-mile pipeline connecting 650 MMcf/d of natural gas supply in Pennsylvania with markets in New York and New England, has experienced several setbacks.

Initially aiming for service in winter of 2016, Constitution was denied a water quality permit by New York state in April 2016, halting preparations for construction. Development of the Constitution Pipeline has effectively been stymied by the legal battle resulting from New York’s permit denial, with an anticipated operational date of mid-2018 if legal issues can be resolved.

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