Power & Utilities Industry Primer

Power & Utilities includes electricity generation (Power), transmission and distribution of a public service (Utilities), usually in the form of electricity, water and heating (gas) – but depending on the jurisdiction, can include telecommunications and broadband services.

Utilities are natural monopolies that end up being regulated monopolies that recover expenses from customers/consumers of energy and earn an allowed, reasonable rate of return on capital invested.

How is Power Generated?

The way that a power company creates its product is by turning its “fuel” into electricity. This is done by converting different forms of energy into electrical energy, usually via mechanical energy by the way of spinning a turbine.

The most prominent feedstocks for power generation include coal, gas, nuclear, hydro, wind and solar. Other methods include the burning of biomass or harnessing geothermal hotspots (for example, volcanoes in Iceland).

Coal, gas and nuclear are thermal technologies, where coal/gas is burned or nuclear reactions heat water to generate high pressure steam. This steam subsequently turns the turbine, whereby a generator transforms the mechanical energy into electrical energy. These three technologies use non-renewable resources as fuel – lignite or subbituminous coal, natural gas or uranium. Coal is widely perceived to be a dirty fuel, while natural gas has carbon emissions, although at a much lower level. Nuclear is a zero-emission fuel.

Hydro, wind and solar are renewable generation methods. In the past, only hydro was seen to be reliable and commercially effective (a river is always running, but the sun only comes up once a day and may be obscured by clouds while wind patterns are difficult to predict). Technology has accelerated and solar is now the cheapest with photovoltaic (PV) panels costing a fraction of what they used to. Solar and wind are both economic without government subsidies in many jurisdictions. Improvements in energy storage have also contributed to the viability of the latter two as consistent electricity providers.

Once electricity is generated, it leaves the power plant and is “stepped-up” at a substation (voltage is increased), allowing for fast travel through transmission lines before reaching its destination. At the regulated utility, the electrical current is stepped-down at another substation before being distributed to residences and commercial consumers of energy.

Major Canadian Power and Utilities Companies

Generation in Canada is conducted by independent power producers (IPPs) or integrated utilities – utilities involved in all parts of the electricity value chain, from generation to distribution.

Major IPPs in Canada include Capital Power [TSE:CPX], TransAlta [TSE:TA], Boralex [TSE:BLX], Algonquin [TSE:AQN], Innergex [TSE:INE] and Northland Power [TSE:NPI].

Canada generates most of its power using hydroelectric dams. Coal was dominant in Alberta, but country-wide initiatives have seen coal being almost eliminated as a feedstock for the electrical grid. Environmentalist and anti-coal sentiment in Canada has distressed thermal coal stocks, although cheap coal from the Powder River Basin is still finding its way to developing markets with growing electrical grid demand.

The Economics of Power Generation

The revenue function for power companies has a price component and a volume component – however, for evaluating operating performance, a net revenue figure is more relevant than the first top line item.

For volume, it is important to first consider the capacity of a generation asset. The capacity is the designed maximum amount of electricity that the power plant can generate, as measured in megawatts (MW), although if the plant is large enough this may be in gigawatts (GW).

Capacity can be taken offline if there is a maintenance turnaround at the facility, in which case the generator will be taken off the grid for that time. All power plants will need repairs and checks, but there is a big difference between planned turnarounds, which are hopefully completed below budget and ahead of schedule, and unplanned turnarounds, which are unfavorable to a generator’s profits.

After looking at the capacity, the utilization should be evaluated – or how much of the capacity is being used throughout the fiscal period. This will depend on demand during base, intermediate and peak times throughout the day.

Baseload Power Generation

Coal, nuclear, hydro and combined-cycle natural gas plants are used as baseload power. This is the power that is necessary to sustain minimum electricity use during the day (heating, cooling, lights). The best illustration would be night time, when most people are asleep and the power is off. Ideal baseload power has high fixed costs and low variable costs, all of which are evident in coal, nuclear, and hydro. For natural gas baseload power, a plant may have to lock in long-term supply contracts to ensure that it is always economic.

Intermediate Power Generation

There is electricity required on top of what the base load power provides, usually during high usage times of the day such as work hours. Combined-cycle natural gas is generally the preferred intermediate power generation source as feedstock is relatively low cost and ramping up utilization is simple. Should sufficient quantities of wind or solar power be available, these will be used instead.

Peak Demand Power Generation

When temperature spikes during the summer or drops precipitously in the winter, there may be a peak demand which is substantially above intermediate levels (especially during heat waves and blizzards). Peak demand is satisfied by low fixed cost, high variable cost generation – usually in the form of simple combustion cycle natural gas plants that can be fired up immediately. These will kick in once the market price for electricity reaches a point which satisfies their return on equity hurdles to start up the plant. Average peaker plant utilization is around 10-20%.

Unreliable Power

For unreliable forms of power such as wind and solar, their low cost when the “fuel” (wind and sunlight) is available mean that they are extremely profitable (depending on the prevailing cost of electricity during the time their fuel is available) when they are operating when power is needed in excess of contracted base power. This dynamic may change drastically should there be technological advances in energy storage via through batteries or other means.

Each jurisdiction is different and gains from trade are certainly possible from power generation. British Columbia, with its vast hydroelectric capabilities can generate electricity and sell down to neighbouring states and provinces (Washington State and Alberta) cheaper than it is for the electricity to be generated in Washington or Alberta – however, they will charge whatever the prevailing market rate is there. Price arbitrage illustrated here gives rise to opportunities in electricity trading, with prominent firms including Powerex (BC Hydro’s electricity marketing arm), Morgan Stanley, TransAlta and Capital Power.

The actual volume sold is measured in megawatt-hours (MWh) – and considers both utilization and capacity. The MWh of electricity generated will be a function of available capacity (the MW capacity times available hours) multiplied by the utilization rate.

The price function for power generation depends on a multitude of factors.

The Power Price Cost Curve

Without regulatory distortions, the power price is determined by the equilibrium of electricity supply and electricity demand.

In a simplified version of Vancouver, we can say that BC Hydro has hydroelectric power with no variable costs with 500MW of capacity. There are two natural gas plants, both with 100MW of capacity – however one can get cheaper natural gas and has a variable cost of $10/MWh while the other has a variable cost of $20/MWh.

The baseload demand in Vancouver is 550MW. As such, the power price is currently $12/MWh, allowing for the first natural gas plant to recover its variable cost plus a 20% return on investment. The hydroelectric dams are running at 100% utilization and earning net revenue of $12/MWh * 500MW per hour, or $6,000. The gas plant is earning net revenue of $2*50 = $100 per hour.

A blizzard stresses the power system and the demand curve shifts to the right. Now demand is 650MW. The peaker plant fires up and the new equilibrium price is $24/MWh. Now the hydroelectric dam makes $24MWh*500 while the first plant makes $14/MWh*100 and the second plant makes $4MWh*50.

The Spark Spread

The spark spread is the most well known measure of net revenue for power producers. The spread is the difference between the sale price of electricity less the price of generation.

As an example, the market price in Alberta is $25 per MWh while AECO (the natural gas benchmark in Alberta) is $2 per mcf (thousand cubic feet) or MMBtu (million British thermal units). To generate enough heat to fire up the plant, 10MMBtu of energy content is needed. The spark spread is accordingly calculated as follows: $25 – $2*10 = $25 – $20 = $5, resulting in $5 in net revenue per MWh for a 25% margin.

The spark spread is the appropriate term for natural gas fired generation only. Other spreads include the dark spread (coal) and quark spread (nuclear using uranium).

Power Price Drivers

In the previous example, the spot price of AECO was used as an offset to the spot price of electricity. Realistically, one or both variables usually would not be contracted at spot as that would make cash flows far too volatile. Most power generation projects are financed by banks initially, which means that they want surety of cash flow. In addition to that, the equity investors behind the power project will also want to lock in a rate of return that hurdles for them to compensate them for their funds.

Power Purchase Agreements

A certain amount of electricity is contracted out to an offtaker at a locked in price, which may come with step-ups. Many power plants will transact in 20 year PPAs that ensure profitability.

Fuel Purchase Agreements

Similarly, a generator may want to lock in the price it pays for its fuel in long-term agreements. This may be done directly with a coal company or gas company. Cameco deals with several nuclear power plants.

Forward Agreements

Usually shorter term than PPAs, but forwards can lock in prices via derivative contracts both on the electricity side (revenue) and on the physical commodity side (cost).

Spot Electricity Price

The risk-reward profile is clear for generators. Spot will yield the highest expected return but will be the most volatile, with the possibility of not recuperating the initial investment. Whenever long-term power is sold, it generally will be at a discount to the market price, so spot prices realized via peaker plants tend to generate the highest IRRs but the lowest volumes.

Take-or-Pay Contracts

A certain amount of capacity is made available by the purchaser of electricity and they will pay for it regardless. However, if it is not taken off by that counterparty for whatever reason, electricity can be sold to someone else.

Utilities Primer

The generation and distribution of power via utilities requires massive amounts of capital and infrastructure. These companies are natural monopolies and will tend to have only one key player in each service area.

While the revenues for the generation aspect of the business is based on cost and the market, the transmission and distribution aspect of the business is highly regulated. Utilities will either be integrated or standalone entities.

1. Integrated Utility: a company is vertically integrated and runs all three levels of the supply chain (generation, transmission and distribution). Hydro Quebec is an example of an Integrated Utility company.
2. Transmission and Distribution: a company runs the transmission and distribution aspect of the business and delivers energy to the public. Transmission is the delivery of the utility from the generation plant to the sub-stations at high voltages. Distribution then brings the power from the sub-stations to end users at voltages that can be used for retail/commercial use. Since utilities are seen as goods necessary to the public, the industry is highly regulated. In Canada, the provincial governments have legislative authority to regulate the utilities industry. In Ontario, the Ontario Energy Board will review and approve electricity rates. Hydro One is an example of a transmission and distribution company.

Revenue generation for transmission and distribution are different from that of a typical company in which runs top to bottom. Typically, a company generates revenues by selling products and costs/expenses are deducted to reach Net Income. Power & Utilities companies work the opposite way and is centered on each respective company’s “Rate Base” and “Allowed Rate of Return”. This methodology is called “cost of service” and the determination of revenue is a based on the company generating enough after-tax income to yield an adequate return on the equity while also covering any costs and expenses.

Power generation companies make money by generating electricity via transforming their “fuel” and then selling this electricity to the open market. The difference between the price they receive and the cost of generating the electricity is the operating profit. The price they receive depends on whether electricity markets are regulated and the terms of their contract with the party that buys the electricity (the offtaker).

The only unregulated energy market in Canada is in Alberta, which theoretically means lower average power prices but also makes the Province susceptible to supply shocks and price spikes (especially during the coldest months of winter).

Each Utility company will apply a rate case each year to receive approval from the regulating body on their, Rate Base, Deemed Capital Structure and Allowed ROE. The Rate Base is the value of the company’s regulated fixed assets minus depreciation. The deemed capital structure is typically 60% debt and 40% equity.

“Deemed Equity”: 40% x Rate Base

“Deemed Debt”: 60% x Rate Base

“Allowed ROE” is a contested subject and the formula used varies across different regulating bodies. In Ontario, the following formula for the determination of Allowed ROE is used:

Allowed 𝑅𝑂𝐸𝑡 = 9.75% + 0.5 × (𝐿𝐶𝐵𝐹𝑡 − 4.25%) + 0.5 × (𝑈𝑡𝑖𝑙𝐵𝑜𝑛𝑑𝑆𝑝𝑟𝑒𝑎𝑑𝑡 − 1.415%)

Where 𝐿𝐶𝐵𝐹𝑡 is the 30 year GoC Bond and 𝑈𝑡𝑖𝑙𝐵𝑜𝑛𝑑𝑆𝑝𝑟𝑒𝑎𝑑𝑡 is the spread on the corporate bond of an A-rated Utility company over the GoC Bond. Historically the ROE has remained quite tight, ranging from 8.93% to 9.85% in Ontario from April’99 to Jan’16.

Allowed ROE multiplied by Deemed Equity will yield an adequate Net Income and return on equity. The debt cost component of the company needs to be considered also and is achieved similarly. Deemed Debt multiplied by the interest rate equates to the company’s debt cost. Now, we have the company’s cost of capital, and adding the cost and expenses will derive a utility company’s Required Revenue.

(Deemed Equity x Allowed ROE) = Net Income

Net Income + Taxes + (Deemed Debt x Interest Rate) + Depreciation/Amortization = EBITDA

Expenses (cost of power, operating costs, maintenance costs, etc.) are added on to reach the company’s Required Revenue.

Valuation of Power & Utilities Companies

Valuation of a utility company is done through the basic methods such as comparable companies and precedent transactions comps analysis. You’ll also see more of DCF and Dividend Discount Models as Utility companies generally tend to have steady cash flows thanks to the business model and many utility stocks provide dividends.

Regulated Utility Valuation

• Price/Forward earnings
• Price/Tangible book value (TBV)
• Enterprise Value/Rate Base
• EV/Customers

Integrated Utility Valuation

• Price/Forward earnings
• EV/EBITDA
• Price/Tangible book value
• EV/Rate Base

Power Generation Valuation and Power Portfolio Evaluation

• EV/EBITDA
• Price/Forward Earnings
• EV/Capacity ($/Megawatt)

When power investment bankers put together teasers or confidential information memorandums (CIM) on power producers, a summary of assets is provided in this format.

1. Current Operating Assets – Assets already generating power
2. Assets Under Construction – Assets that are project financed and will generate power at a future commercial operation date
3. Development Pipeline – Greenfield power generation plants that have not started construction yet and are in varying stages of engineering and regulatory approval

Each segment will highlight the capacity (in terms of MW) in gross and net terms (the cumulative generation capacity of the assets and the amount that belongs to the power company being evaluated – for instance, a 75MW wind farm that belongs 50% to Brookfield Renewable Energy Partners and 50% to Capital Power will have net capacity of 37.5MW for each)

Here is an example power portfolio for SSHB Power:

Operating Assets (150MW Gross Capacity, 100MW Net Capacity, 3 Assets)

• Zhongshan Wind Farm 50 MW (100% owned)
• Zhuhai Solar Farm 50 MW (50% owned)
• Bogota Biomass Plant 50 MW (50% owned)

Assets Under Construction (150MW Gross & Net Capacity, 3 Assets)

• La Paz Wind Farm 50 MW – COD expected January 2018
• Santiago Solar Farm 50 MW – COD expected June 2018
• Edmonton Biomass Plant 50 MW – COD expected March 2019

COD is the Commercial Operation Date, which is the date when testing is complete and when the producer can start selling power.

Development Pipeline

• Chongqing Wind Farm 50 MW – Construction to begin 2019
• Jiangsu Solar Farm 50 MW – Construction to begin 2020

In addition to this, analysts may want to see the utilization for the operating assets and the going rate for power.

Modelling a Single Power Asset

Assume there is a 10 MW wind farm in Alberta. It is utilized 25% of the time. It is contracted to an offtaker utility company for $25/MWh that is stepped up by inflation each year. Inflation is 2%.

Capacity: 10MW
Annual Capacity: 10MW x 24 hours x 365 days = 87,600 MWh or 87.6 GWh
Utilization: 25%
Annual Production: 21,900 MWh
Power Price: $25/MWh
Year 1 Revenue 21,900*25

Then take off all the operating expenses and fuel costs. Increase by inflation each year and discount the cash flows for the duration of the PPA.

In a spot market where the asset is not contracted, input price assumptions.

Power & Utilities Credit

Independent Power Producers Credit

There is ample credit extended to power generators via loans and bonds. Here are some of the major considerations from a credit standpoint. As per usual, spot is not favored and certainty is the best security.

Offtake – Creditors like to see electricity supply being contracted out, especially via long-term PPAs. As PPAs approach maturity, certainty falls. If an entity declares force majeure and reneges on the PPA, creditors will feel uneasy.

Regional Spot Demand – The strength of the offtake is not only limited to what is available in contract but also what the regional market demands. If the IPP is low cost with high electricity needs, there is certainty of offtake at favorable prices even if there are no contracts.

Position on the Cost Curve – The lower the cost, the more of a buffer the IPP has in terms of depressed energy prices.

Strength of Counterparties – Most utilities are creditworthy and regulated at the provincial or state level. In industrial areas, power demand may be influenced by other macroeconomic factors and a defaulting client may spell trouble.

Integrated Utilities Credit Evaluation

Some qualitative factors that impact credit are:

Market Volatility for non-regulated earnings (power generation): Demand will be largely influenced by factors such as regional industrial activity. For example, aluminum and pulp and paper industries require massive amounts of electricity and declining activities in these areas can drop market demand for power. Weather will also have a substantial impact on residential demand as hot summers will lead to higher usage of space cooling (air conditioning).

Capital Intensity: The industry requires heavy capital investments for projects such as the addition of transmission lines, new power generation plants, and acquisitions. Over committing on capital spending can lead to leaner cash supply so it is important to look at the company’s earnings and cash flows to ensure they are stable and sufficient to cover the capex (and dividends). It is also important to know whether the capital spending will be constituted as a regulated fixed asset as this will help increase the rate base and ultimately the Deemed Equity.

Regulatory Risk: Since the transmission and distribution businesses in utility companies are exposed to regulatory changes, it is important to understand if there are any material and substantial changes to the regulations and policies that may affect the business. For example, changes to the calculation methodology for Required Revenue will obviously have a material impact on a utility company’s earnings.

Environmental Risks: The shift towards cleaner energy and lower GHG emissions is shaping the way power generation companies look at for power sources. Utility companies that depend on coal fired generation plants will have more difficulty moving forward.

Deemed Equity and Allowed ROE: Deemed Equity multiplied by the Allowed ROE is what the Utility company can earn. A higher Deemed Equity or Allowed ROE will result in greater earnings for the company.

Some quantitative metrics/figures that are looked at are:

EBITDA/Net Sales: How efficiently the company is operating and managing their capital.

Debt/EBITDA: Power & Utility companies are capable of withstanding higher levels of leverage thanks in part to their resiliency to economic fluctuations and stable cash flow. Ratios may push up to 5X and 6X.

Debt/Capital: Although utilities are able to take on more leverage, many have extended themselves in acquisitions.

EBITDA/Interest: Ability to service debt interest payments. Typical among any credit analysis.

EBITDA – CAPEX/Interest: Ability service debt interest payments after CAPEX is important given the large capital spending requirements (see above).

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