Electricity revenue recognition example

Electricity revenue recognition example

Application of the five-step model

Facts: Bundle Seller Co (‘Seller’) and Bundle Buyer Co (‘Buyer’) executed an agreement for the purchase and sale of 1oMW of electricity per hour and the associated renewable energy credits (‘RECs’) (one REC for each MWh) at a fixed bundled price (‘the agreement’ or ‘the PPA’). The contract term begins on 1 January 20X1 and ends on 31 December 20X4, and the fixed bundled price during each of those respective years is $200, $205, $210 and $215.

The increase in the bundled price represents the increase in the forward price of electricity and RECs over the term of Electricity revenue recognition examplethe agreement as of the acquisition date. Control, including title to and risk of loss related to the electricity, will pass and transfer on delivery at a single point on the electricity grid. Control, including title to and risk of loss related to RECs, will pass and transfer when the associated electricity is delivered.

Seller and other market participants frequently execute contracts for the purchase and sale of electricity and RECs on a stand-alone basis.

Seller concluded that this arrangement does not contain a lease (that is, no property, plant or equipment is explicitly or implicitly identified). The electricity element of this arrangement qualifies for the ‘own use’ exception and thus is not accounted for as a derivative. The REC element has no net settlement characteristics. As such, each element of this agreement is within the scope of IFRS 15.

Electricity revenue recognition – IFRS 15 step-by-step

Step 1 – Identify the contract with a customer

This agreement, including each of its elements (that is, electricity and RECs), is within the scope of the standard, and collection of the contract consideration is considered probable.

Step 2 – Identify the performance obligations

The electricity element represents a promise to transfer a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer; therefore, the electricity represents one performance obligation that is satisfied over time. This conclusion is based on the following factors:

  1. The electricity is distinct, because (a) Buyer can benefit from the electricity on its own (that is, Buyer can sell Electricity revenue recognition exampleelectricity, on a stand-alone basis, into the marketplace), and (b) the promise to transfer electricity is separately identifiable from other promises in the contract (that is, the electricity is not an input to produce or deliver a combined output to Buyer, the electricity does not significantly modify or customise another promise in the contract, and the electricity is not highly dependent on, or highly interrelated with, other promised goods in the agreement).
  2. The performance obligations to deliver electricity are satisfied over time, since Buyer simultaneously receives and consumes the benefits provided by Seller’s performance as Seller performs.
  3. Each distinct transfer of electricity in the series that Seller promises to transfer to Buyer meets the criteria to be a performance obligation satisfied over time, and the same method will be used to measure Seller’s progress towards complete satisfaction of the performance obligation to transfer each distinct good in the series to Buyer.

The monthly promise to transfer RECs to the customer during the term of the Power Purchase Agreement (‘PPA’) (48 deliveries) represents goods that are distinct, based on the following:

  1. Buyer can benefit from the RECs on its own (that is, Buyer can sell RECs, on a stand-alone basis, into the marketplace, so the RECs are capable of being distinct); and
  2. the promise to transfer RECs is separately identifiable within the PPA (that is, the RECs are distinct within the context of the contract).

Each promise to deliver RECs is a separate performance obligation that is satisfied at a point in time, because none of the criteria are met to account for such promises as performance obligations satisfied over time.

Step 3 – Determine the transaction price

The transaction price is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods to a customer. Under the terms of the arrangement, Seller will sell 10 MW per hour during each hour of the four-year contract term at fixed bundled prices, which escalate during each year of the contract term. The transaction price is $72,708,000. The table below illustrates the computation to arrive at the transaction price.

Contract year

Contract price ($)

/MWh

Contract volume¹ MWh

Amount in $

1

200

87,600

17,520,000

2

205

87,600

17,958,000

3

210

87,600

18,936,000

4

215

87,600

18,834,000

Total

350,400

72,708,000

1. Annual contract quantities were calculated as follows: 10 [MW per hour] * 24 [hours per day] * 365 [days per year].

Step 4 – Allocate transaction price to the performance obligations in the contract

The promise to transfer electricity to the customer represents one performance obligation that is satisfied over time; the monthly promise to transfer RECs to the customer represents individual performance obligations that are satisfied at a point in time.

The transaction price should be allocated to each performance obligation, based on the relative stand-alone selling prices of the goods being provided to the customer. To do so, Seller should determine the stand-alone selling price (‘SSP’) at contract inception of the distinct good underlying each performance obligation in the bundled arrangement and allocate the transaction price in proportion to those SSPs.

Since Seller frequently sells electricity and RECs on a stand-alone basis in the normal course of its operations, the priceElectricity revenue recognition example that it charges for electricity and RECs when it sells them separately to similar customers is the best evidence of the SSP.

As a result, Seller is not required to estimate or derive the SSP of either electricity or RECs; rather, it will use those SSPs for the purposes of allocating the transaction price, which reflects the forward prices as of the date when the contract was executed.

The SSP for the electricity and RECs was calculated as follows:

Year

SSP²

Electricity

SSP²

REC

Quantity

Total SSP

Electricity

Total SSP

REC

Grand total

SSP

20X1

$41/MWh

$162/REC

$87,600

$3,591,600

$14,191,200

$17,782,800

20X2

$43/MWh

$165/REC

$87,600

$3,766,800

$14,454,000

$18,220,800

20X3

$45/MWh

$168/REC

$87,600

$3,942,000

$14,716,800

$18,658,800

20X4

$47/MWh

$171/REC

$87,600

$4,117,200

$14,979,600

$19,096,800

Total

$15,417,600

$58,341,600

$73,759,200

2 In this fact pattern, Seller has determined that the SSP for electricity and RECs represents the forward prices for electricity and RECs as of the date when the contract was executed. The allocation is not updated for changes in the SSP of electricity and RECs subsequent to contract inception.

Seller would allocate the transaction price to the electricity, which represents one performance obligation satisfied over time, as follows:

Electricity:

$15,197,872 = ($72,708,000 * ($15,417,600 [SSP] / $73,759,200 [grand total SSP]

Seller would allocate the transaction price to the RECs, which represent individual performance obligations that are satisfied at a point in time, as follows:

Year

Annual amounts³

Calculation

20X1

$13,988,950

$72,708,000 * ($14,191,200 [SSP]/$73,759,200 [total SSP])

20X2

$14,248,005

$72,708,000 * ($14,454,000 [SSP]/$73,759,200 [total SSP])

20X3

$14,507,059

$72,708,000 * ($14,716,800 [SSP]/$73,759,200 [total SSP])

20X4

$14,766,114

$72,708,000 * ($14,979,600 [SSP]/$73,759,200 [total SSP])

Total

$57,510,128

3 Immaterial difference might arise due to rounding.

The excess of the sum of the SSPs of the electricity and RECs ($73,759,200) over the promised consideration ($72,708,000) represents a discount that Buyer is receiving from Seller for purchasing a bundle of goods. By allocating based on the relative SSPs, the discount of $1,051,200 is allocated proportionately to each performance obligation.

The discount allocated to electricity is $219,728 ($1,051,200 * ($15,417,600/$73,759,200)). The discount allocated to the performance obligations to deliver RECs in January and February 20X1 is $17,177 ($1,051,200 * ($14,191,200 * (31/365))/$73,759,200) and $15,515 ($1,051,200 * ($14,191,200 * (28/365))/$73,759,200), respectively. The aggregate discount attributable to the 48 performance obligations to deliver RECs is $831,472 ($1,051,200 * ($58,341,600/$73,759,200)).

Step 5 – Recognise revenue when (or as) the entity satisfies a performance obligation

Seller should recognise revenue when (or as) it satisfies a performance obligation by transferring a promised good (that is, an asset) to Buyer. An asset is transferred when (or as) Buyer obtains control of that asset. Buyer obtains control of a good if it has the ability to direct the use of and obtain substantially all of the remaining benefits from that good.

Seller transfers control of the electricity over time, and Buyer simultaneously receives and consumes the benefits provided by Seller’s performance as it performs; therefore, Seller would satisfy its performance obligations and would recognise revenue on sales of electricity over time by measuring the progress towards complete satisfaction of its performance obligation to deliver electricity. The objective when measuring progress is to depict Seller’s performance in transferring control of the electricity to Buyer. Seller transfers control of the RECs at a point in time; therefore, Seller recognises revenue in the month in which the associated electricity is delivered.

IFRS 15 includes a practical expedient that allows an entity to recognise revenue in the amount at which the entity has a right to invoice if that amount corresponds directly with the value to the customer of the entity’s performance to date. Judgement might be required to conclude whether invoiced amounts correspond directly with the value to the customer, and application of the practical expedient might not be appropriate in this fact pattern.

Revenue should be recognised when control is transferred for each performance obligation (that is, electricity and RECs on delivery to the electricity grid). If Seller concludes that application of the practical expedient is appropriate, Seller would recognise revenue on the first three monthly deliveries of electricity and RECs as follows:

PO

January 20X1

February 20X1

March 20X1

Total

Electricity revenue¹

$300,502

$271,421

$300,502

$872,425

REC revenue²

$1,187,498

$1,072,579

$1,187,498

$3,447,575

Total

$1,488,000

$1,344,000

$1,488,000

$4,320,000

1 Calculated as the product of fixed quantities delivered (7,440, 6,720 and 7,440 MWh in January, February and March, respectively) and the allocated per unit transaction price of $40.39/MWh. The allocated per unit transaction price is the fixed bundled price ($200.00) multiplied by the proportionate share of the relative SSP ($3,591,600/$17,782,800).

2 Calculated as the product of fixed quantities delivered (7,440, 6,720 and 7,440 RECs in January, February and March, respectively) and the allocated per unit transaction price of $159.61/REC. The allocated per unit transaction price is calculated as the fixed bundled price ($200.00) multiplied by the proportionate share of the relative SSP ($14,191,200/$17,782,800). Note that revenue is recognised in the period when the associated electricity is delivered.

The total amount of revenue recognised by Seller for the first three monthly deliveries of electricity and RECs ($4,320,000) is equal to the sum of the three monthly invoices billed to Buyer in January, February and March 20X1 of $1,488,000 (10 [MW per hour] * 24 [hours per day] * 31 [days in January] * $200 [bundled price]), $1,344,000 (10 [MW per hour] * 24 [hours per day] * 28 [days in February] * $200 [bundled price]), and $1,488,000 (10 [MW per hour] * 24 [hours per day] * 31 [days in March] * $200 [bundled price]), respectively.

Note: In practice, a reporting entity’s conclusions might differ from the above on similar bundled arrangements, based on, among other factors:

  1. the underlying economics of the arrangement, including the conclusion on whether the contractual pricing corresponds directly with the value to the customer over the contractual term;
  2. the market constructs (for example, RECs might not represent a separate performance obligation in all markets);
  3. the composition of its sales portfolios (for example, electricity or RECs might not be sold on a stand-alone basis, so it might be necessary to estimate SSPs); and
  4. conclusions regarding when control is transferred (for example, a reporting entity might conclude, in certain facts and circumstances, that transfer of control of RECs occurs on the transfer of RECs into Buyer’s accounts).

Annualreporting provides financial reporting narratives using IFRS keywords and terminology for free to students and others interested in financial reporting. The information provided on this website is for general information and educational purposes only and should not be used as a substitute for professional advice. Use at your own risk. Annualreporting is an independent website and it is not affiliated with, endorsed by, or in any other way associated with the IFRS Foundation. For official information concerning IFRS Standards, visit IFRS.org or the local representative in your jurisdiction.

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