ACCOUNTING AND AUDITING UPDATE - assets.kpmg · Accounting Advisory Services KPMG in India KPMG in India has introduced a revamped series of the Accounting and Auditing Update which

Issue no. 2/2015 | Power

ACCOUNTINGAND AUDITINGUPDATE

IN THIS EDITION

Revenue recognition in the power sector p1

Service concession arrangements and embedded leases p7

Depreciation rate for electricity companies p13

Accounting for rate regulated activities p15

Impact of GST on the power sector p19

Income Computation and Disclosure Standards p21

Accounting for government grants by companies in the renewable energy industry p25

Borrowing cost in the power sector p27

Regulatory updates p29

© 2015 KPMG, an Indian Registered Partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.© 2015 KPMG, an Indian Registered Partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.© 2015 KPMG, an Indian Registered Partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.

Jamil Khatri

Partner and Head Assurance KPMG in India

Sai Venkateshwaran

Partner and HeadAccounting Advisory Services KPMG in India

KPMG in India has introduced a revamped series of the Accounting and Auditing Update which will bring to you recent affairs on the accounting, financial reporting and regulatory challenges being faced by diverse sectors in India. Each month’s publication focusses on a different sector. This month, we explore various aspects related to the power sector.

Revenue recognition under the new revenue standard, Ind AS 115, Revenue from Contracts with Customers, is expected to pose challenges to the power sector. This area is further complicated by the potential deferment of the Ind AS 115 and the likelihood of the application of Ind AS 18, Revenue and Ind AS 11, Construction Contracts along with the guidance on service concession arrangements, barter transactions involving advertising services, customer loyalty programmes and transfers of assets from customers. We have analysed the five-step model needed to be applied under the Ind AS 115 and highlighted the key impact areas under the same.

The sector and its entities could get covered in the scope of the new guidance on the service concession arrangements and embedded leases. The publication also places emphasis on the accounting requirements related to these areas.

Additionally, certain power sector entities are governed by regulations setup by the government, e.g. tariff earned is governed by the Central Electricity Regulatory Commission (CERC) and the State Electricity Regulatory Commission (SERC). Our article on rate regulation provides an overview on the guidance note on Accounting for Rate Regulated Activities and Ind AS 114, Regulatory Deferral Accounts. We have also discussed the implications of other Ind AS on rate regulated entities, e.g. income taxes, earnings per share, impairment of assets, consolidated financial statements and presentation.

The power sector is capital intensive in nature, and hence, considerations around depreciation and borrowing costs are significant for several companies.

Our articles on the same highlight some of the nuances and challenges associated with applying judgements and accounting policies in these areas.

We also highlight salient aspects of the Goods and Services Tax (GST) and Income Computation and Disclosure Standards (ICDS) in addition to our regular round up of regulatory updates.

As always, we would be delighted to receive any kind of feedback or inputs on the topics that we have covered.

Editorial

© 2015 KPMG, an Indian Registered Partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.

© 2015 KPMG, an Indian Registered Partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.© 2015 KPMG, an Indian Registered Partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.© 2015 KPMG, an Indian Registered Partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.

As one of the largest consumers of power in the world, accompanied with an impressive growth rate in real terms over the last decade, India has developed a diversified generation model covering both conventional and non-conventional sources. As per the latest available data with the Ministry of Power, the Government of India, updated till 31 August 20151, total thermal (coal, natural gas and oil) generation is pegged at around 70 per cent of the total installed capacity; while hydro, renewable energy sources and nuclear power contribute to the balance 30 per cent. Further, the government is promoting power generation from renewable energy resources by offering various incentives.

With speedy expansion of the economy, the demand for electricity is expected to go beyond 950,000 Mega-Watt (MW) by 20302. With a current installed

capacity of approximate 277,000MW1, the government has its task cut out. Earlier this year, the Minister of State for Power, Coal, New and Renewable Energy, addressed a press conference in New Delhi and said that 22,566MW of generation capacity was added in the last one year and future plans of the government include an ambitious target to increase the power generation from renewable energy five fold to 175,000MW by 20222.

The demand for power in the country is on the rise due to various factors such as growth of the manufacturing sector, increase in residential consumption, rapid urbanisation, connection of many new villages to the grids, etc.

The Indian power industry is characterised as one that is highly regulated and dominated by central

and state sector utilities, across the entire value chain. Consequently, policies and regulations play a pivotal role in the development of this sector. Some key challenges that have plagued development include allocation and supply of coal, land acquisition, environment clearances, transmission losses, etc.

The industry faces a great deal of accounting and regulatory issues arising out of the governing laws and regulations, power purchase agreements, operational issues, etc.

This publication examines some of the key financial, accounting and regulatory issues that are expected to be encountered by the industry in the near future.

Overview


1. http://powermin.nic.in/power-sector-glance-all-india

2. Newspaper reports

Business standard - Households vital for India’s energy independence, says scientist dated 6 March 2015.

Business Line - Power capacity addition at record 22,566 MW in past 1 year: Goyal dated 27 May 2015.

Revenue recognition in the power sectorThis article aims to:

– Highlight key accounting principles for companies operating in the power sector under Ind AS 115. – Showcase key impact areas on the power sector from the application of these new accounting principles.

In May 2014, the International Accounting Standards Board (IASB) and the Financial Accounting Standards Board (FASB) published a new joint standard on revenue from contracts with customers – IFRS 15. This standard replaces International Accounting Standard (IAS) 11, Construction Contracts, IAS 18, Revenue, IFRIC 13, Customer Loyalty Programmes, IFRIC 15, Agreements for the Construction of Real Estate, IFRIC 18, Transfers of Assets from Customers and SIC 31, Revenue-Barter Transactions Involving Advertising Services.

Under the current Indian GAAP, Accounting Standard (AS) 7, Construction Contracts and AS 9, Revenue Recognition are the two standards that provide general guidance on revenue recognition. The guidance note on Accounting for Rate Regulated Activities provides the accounting treatment for recognition of revenue, assets or liabilities arising out of rate regulation.

In India, Ind AS 115, Revenue from Contracts with Customers is the standard on revenue recognition that is converged with IFRS 15, Revenue from Contracts with Customers. Unlike IFRS 15, accounting guidance with respect to service concession agreements has been included as an appendix to Ind AS 115.

The effective date of IFRS 15 has been deferred by a year to 1 January 2018. Companies in India may accordingly be required to adopt the new revenue standard before it is globally adopted. As a result, there has been a growing

debate in India on whether to defer the implementation of Ind AS 115 (IFRS 15 equivalent) until 2018, when IFRS 15 will be mandatorily adopted globally. Recently, the National Advisory Committee on Accounting Standards (NACAS) has made recommendations to the Ministry of Corporate Affairs (MCA) to defer the implementation of the standard based on global cues. Consequently, on 24 September 2015, the Institute of Chartered Accountants of India has issued two exposure drafts on Ind AS 11, Construction Contracts and Ind AS 18, Revenue.

Revenue recognition in the power sector is primarily dependent on the terms and conditions enlisted in the power purchase agreement. Currently, revenue recognition in this sector is accounted for as per AS 9. The standard prescribes preconditions with respect to revenue recognition such as transfer of significant risk and rewards of ownership to the buyer, transfer of control to the buyer, reasonability of receipt of consideration, reliable measurement of revenue, etc. Ind AS 115 proposes a five-step model of revenue recognition. Under this standard, an entity would have to identify the contract which is the basis for revenue recognition, identify the performance obligations (promise to deliver goods or services) in that contract, determine the transaction price and allocate the transaction price to the various performance obligations before actually applying revenue recognition principles.


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In the case of tariff regulated entities, the amount of revenue recognised in the power sector may not be affected by the new standard; while in the case of power generation entities, there could be uncertainty for certain types of revenue stream. For both these types of entities, the timing of revenue and profit recognition may also be impacted. The timing of revenue recognition may be changed by the identification of separate performance obligations and the required determination of the transaction price under Ind AS 115.

Situations such as contract modifications, variable considerations, take or pay considerations, transfer of assets from customers, which are peculiar to the power sector, could also have an impact on the timing of revenue recognition. The same has been discussed in more details later in this article.

The five-step model of revenue recognition as per Ind AS 115 is discussed below. The impact of Ind AS 115 would vary by industry to industry. For the power sector entities, the step 1 and step 3 are most likely to affect the current practice of revenue recognition.

Contracts that create enforceable rights and obligations and which have commercial substance would fall within the scope of the new standard. The enforceable rights and obligations may be written, oral or implied by the entity’s customary business practice. Termination clauses of the agreements entered into by the power companies would have to be evaluated to conclude on the existence of a contract. If each party to the contract has a unilateral right to terminate a wholly unperformed contract without compensating the other party, then the standard states that a contract does not exist.

Contract modifications

Contract modifications are a common feature of the power sector. The modifications occur mainly due to an extended period of the contract or a change in the contract price or both. An entity would have to account for a contract modification as a separate contract depending on whether distinct goods and services are added to the arrangement and, if so, whether those goods and services are priced at their stand-alone selling price. Otherwise, contract modifications are accounted for either prospectively or by a cumulative catch up adjustment. No such guidance is provided explicitly in the existing standard on revenue recognition.

As such, the companies should:

• Identify the types of contract modifications that are customary for the business and determine whether they will require prospective or cumulative catch-up accounting.

• Develop accounting procedures to ensure consistency of application.

• Develop systems and internal controls to track modifications and the relevant methodology to ensure the appropriate application of the new standard.

Ind AS 115 requires an entity to identify the performance obligations in a contract. A performance obligation is a promise in a contract to transfer to a customer a good or service (or a bundle of goods or services) that is distinct.

A good or service is distinct from other goods or services, and so is a performance obligation if:

• The customer can benefit from the good or service either on its own or together with other resources that are readily available to the customer, and

• The entity’s promise to transfer the good or service to the customer is separately identifiable from other promises in the contract.

However, a series of distinct goods or services that are substantially the same and that have the same pattern of transfer to the customer can also be considered to be a single performance obligation.

Ind AS 115 includes additional guidance to help determine whether the above mentioned criteria are met with.

Indicators that a performance obligation is separately identifiable include the following:

• The entity does not provide a significant service of integrating the good or service with other goods or services promised in the contract.

• The good or service does not significantly modify or customise another good or services promised in the contract.

• The good or service is not highly dependent on, or highly interrelated with, other goods or services promised in the contract.

Power sector companies may need to apply significant judgement when they identify performance obligations. For example, in a power purchase agreement, the seller may be required to generate, transmit and distribute energy. All the aforesaid activities are distinct but the standard requires an entity to consider whether they are distinct in the context of the contract before deciding on the performance obligations. In some situations, the seller provides a significantly integrated service and all the distinct services are highly interrelated to each other. Therefore, there could be only one performance obligation which is to provide energy to the buyer.

Identify the contract

Step 1Identify performance obligations

Step 2

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The standard defines transaction price as ‘the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, excluding amounts collected on behalf of third parties (for example, sales taxes).’

Determination of the transaction price will require reviews, estimation and application of judgement especially in situations such as involvement of variable considerations in the contract or inclusion of a financing component in the amount of consideration or existence of a non-cash consideration.

Variable consideration

Variable consideration is included in the transaction price to the extent that it is highly probable and that there will be no significant reversal of the cumulative amount of revenue when any pricing uncertainty will be resolved. This may include, for example, estimates of the price of unbilled energy supplied to customers and retrospective price adjustments. This may also involve additional judgement to determine the appropriate amount of variable consideration to recognise as revenue.

For example, an entity enters into an agreement to sell 50,000 units of electricity in a year at INR10 per unit. However, if the entity is unable to supply the contracted electricity, the price per unit will be reduced by INR1 per unit for deficit of every 5,000 units. In this situation, the company needs to estimate at the beginning of the year that is highly probable about the quantum of ultimate supply. If the company estimates that it can only supply 40,000 units of electricity, then revenue should be recognised for INR8 for each unit delivered (irrespective of the fact that billing may be made at INR10 until the final reconciliation is being done with the customer at the year-end). No explicit guidance on variable consideration is included in AS 9.

Companies in this sector should:

• Identify contracts involving variable consideration and assess its implications for accounting and financial reporting purposes.

• Develop processes, adjust systems and internal controls to capture, report, as well as monitor and reassess contracts with variable consideration and underlying features.

Transfer of assets from customers

Power purchase agreements often require contribution of goods or services (such as property, plant or equipment) from the customer to facilitate fulfillment of the contract. The entity (the power producer) obtains control of the contributed goods or services. Under the new standard, an entity assesses whether it obtains control of the assets received and applies specific guidance provided on non-cash considerations. The entity measures the non-cash consideration received from the customer at a fair value, if that can be reasonably estimated; if not, then the entity uses the stand-alone selling price of the good or service that was promised in exchange for the non-cash consideration.

Non-refundable upfront fees

In many cases, the seller may receive a non-refundable upfront fee as part of the power supply contract. The fee is often for the initial set-up, connecting a customer to an electricity network, providing access to supply of goods or services etc. In several situations, the upfront fee does not relate to transfer of goods or services. Instead, it is an advance payment for future goods or services and therefore, would be recognised as revenue when those future goods or services are provided. The entity should:

• Review the contractual terms of arrangements, involving transfer of assets from customers to assess if the timing of revenue recognition will be affected under the new standard.

• Assess whether the fees relate to the transfer of a promised good or service that needs to be identified as a separate performance obligation.

The standard requires allocation of the transaction price to various performance obligations generally in proportion to their stand-alone selling prices, which are the prices at which an entity would sell a good or service on a stand-alone basis at contract inception. The standard states that the best evidence of a stand-alone selling price is the observable price of a good or service when the entity sells the same separately in similar circumstances to similar customers. The standard also prescribe alternative methods for determining the transaction price when the selling price of goods or services is not observable such as the adjusted market assessment approach, expected cost plus margin approach and the residual approach (in limited cases).

Entities may face difficulties in determining the stand-alone selling prices of performance obligation. For instance, electricity can be sold at different prices to different customers depending upon the financial credibility of the customer, payment terms, quantum of supply, etc. Similarly, if an entity determines performance obligations based on time in long-term service agreements, then selling price of a good or service sold today cannot be expected to be the same when sold at a future date. Entities should:

• Develop new processes and adjust systems and internal controls to capture, estimate and monitor stand-alone selling prices to allocate the transaction price to the performance obligations in the contract.

• Assess whether billing management and related systems and internal controls are capable of supporting the allocation methodology and generation of journals to allocate revenue.

Determine the transaction price

Step 3Allocating the transaction price

Step 4


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An entity would have to recognise revenue when the entity satisfies a performance obligation by transferring a promised good or service to a customer. An asset is transferred when the customer obtains control of that asset. An entity would have to determine at contract inception whether it satisfies the performance obligation over time or at a point in time. In the former case, the entity needs to measure progress (by either the input method or the output method) and recognise over the period if the performance obligation is satisfied. In the latter case, revenue is recognised when the performance obligation is satisfied.

In power purchase agreements, a single unit is considered as a single performance obligation, and performance would be considered to be satisfied at a point in time.

Other issues

Take or pay arrangements

The standard introduces a new approach for arrangements in which customers do not exercise all of their contractual rights (i.e. breakage). This may affect take or pay arrangements in which customers may not take all of the output to which they are entitled. Under the standard, if an entity expects to be entitled to breakage, it recognises the estimated breakage amount as revenue in proportion to the pattern of rights exercised by the customer. Otherwise, breakage is recognised as revenue only when the likelihood of the customer exercising his/her rights becomes remote. This may change the timing of breakage revenue recognised.

For example, a company entered into a contract for supply of 70,000 units of electricity at INR10 per unit. The quantity is the specified minimum quantity as per the contract and the customer is liable to pay for such quantity, irrespective of whether the customer purchases the minimum quantity. The company is reasonably certain that the customer will purchase only 60,000 units of electricity. Accordingly, INR100,000 (10,000 units at INR10 each) is the breakage revenue. Assuming, the company purchased 5,000 units per month, the breakage will be recognised as revenue equally over the 12 months period. Entities should:

• Review the contractual terms and business practices relating to take or pay arrangements and assess its implications on accounting and financial reporting.

• Develop accounting procedures needed to determine the treatment of breakage in take or pay arrangements.

• Develop processes, systems and internal controls needed to identify and report take or pay arrangements and their key features.

Contract costs

An entity is required to capitalise certain costs incurred in obtaining a contract and, if specified criteria, of fulfilling a contract are met with. This will include capitalisation of sales commissions payable, when a contact is obtained unless the practical expedient is applicable and elected by the entity. Capitalised costs are amortised on a systematic basis consistent with the transfer of associated goods and services, and will be subject to impairment. Judgement will be needed to assess which costs should be capitalised and for determination of the appropriate period and pattern of amortisation, e.g. whether the amortisation period should include the anticipated contracts with the same customer.

The entity should:

• Review typical contract costs against the new capitalisation criteria and determine whether the timing of cost recognition will change.

• Assess whether systems and internal controls are capable of identifying and tracking costs against individual contracts, including anticipated future contracts if relevant, and subsequently amortising over an appropriate period.

Enhanced disclosure requirements

Extensive new disclosures are required as per Ind AS 115, incorporating both qualitative and quantitative information. There are no exemptions for commercially sensitive information. The entity should disclose information about the following:

• Contracts with customers

• Significant judgements

• Assets recognised from the costs to obtain or fulfil a contract with a customer.

For contracts with customers disclosures would include disaggregation of revenue, disclosure of contract balances (receivables, contract assets and liabilities), information about the entity’s performance obligations – value of unsatisfied performance obligations and the timeframe when the same would be satisfied. The stakeholders and competitors may take a close interest in the new disclosures related to unsatisfied performance obligations which might convey information about future activity.

Significant judgements (including changes in those judgements) would include disclosures about judgements that significantly affect the determination of the transaction price, the allocation of the transaction price to performance obligations and the determination of the timing of satisfaction of revenue recognition.

Recognise revenue

Step 5


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For assets recognised from the costs to obtain or fulfil a contract with a customer, disclosures would include closing balances of assets and the amount of amortisation and impairment losses during the reporting period.

Conclusion

Entities need to perform an initial assessment of whether existing systems and processes can collect necessary data required to provide for the new disclosures.

While there is a dilemma over the implementation date of Ind AS 115, decisions might need to be made soon – especially regarding when and how the transition to Ind AS 115 is to take place. The new standard may impact the top line of power and utility companies and related communications with the investors. Companies need to assess how their financial reporting, information systems, processes and internal controls might be affected. In addition, the new disclosure requirements are extensive and might require changes to systems, processes and internal controls for collection of the necessary data.

Impact of exposure drafts on Ind AS 18 and Ind AS 11

It is expected that Ind AS 115 would deferred from early application in India. Though its application date is not announced yet, it is a standard that would eventually be applied in India and globally. When Indian companies would make transition to Ind AS 115, then it is likely that many companies would choose cumulative effect approach i.e. restate all contracts that were not completed under Ind AS 11 and Ind AS 18 requirements at the start of the current period of adoption. Therefore, an impact of all open contracts would require assessment in the period of adoption. As companies enter into long-term contracts which would be open for more than two to three years, then they should not lose sight of the Ind AS 115 requirements. Ind AS 18 and Ind AS 11 do not provide any specific guidance on contract modifications, variable consideration, financing component and capitalisation of contract costs.

(Source: Accounting for revenue is changing - Impact on power and utilities companies – In association with KPMG Global Energy Institute)


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Service concession arrangements and embedded leasesApplicability and accounting implications

This article aims to:

– Summarise the accounting requirements of service concession arrangements and embedded leases.

The power sector is a capital intensive industry and it is often characterised by Public-Private Partnership (PPP) arrangements. In addition, Power Purchase Agreements (PPAs) are common in this industry and these PPAs may extend for periods as long as 25 years.

Considering certain specific requirements of the International Financial Reporting Standards (IFRS) as well as the corresponding Indian Accounting Standards (Ind AS), these arrangements need to be evaluated in detail to study the potential differences in comparison to current Indian GAAP. In certain scenarios, the accounting treatment of such arrangements may lead to significant changes as compared to the current accounting principles and practices under Indian GAAP.

The impact may be so fundamental and significant that the entire expenditure capitalised currently as property, plant and equipment may need to be considered as an intangible asset or a financial asset for accounting purposes in case certain conditions are fulfilled. In certain other situations, the arrangements may be considered as embedded leases.


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Relevant accounting pronouncements for service concession arrangements

There is a specific accounting pronouncement under IFRS to deal with service concession arrangements, namely, IFRIC 12, Service Concession Arrangements. In India, the corresponding requirements are contained in Ind AS 115, Revenue from Contracts with Customers, notified by the Ministry of Corporate Affairs (MCA). Recently, the National Advisory Committee on Accounting Standards (NACAS) has made recommendations to the MCA to defer the implementation

of Ind AS 115. As a consequence of deferral of the applicability of Ind AS 115, the Accounting Standards Board of the Institute of Chartered Accountants of India (ICAI) recently issued an exposure draft on Ind AS 11, Construction Contracts and Ind AS 18, Revenue which includes the proposed requirements with respect to accounting for service concession arrangements. It may be noted that both, the Ind AS 115 as well as the aforesaid exposure draft, do not contain any carve-out with regard to accounting for service concession arrangements and, accordingly, the requirements in the Ind AS are same as in IFRIC 12.

IFRIC 12 does not contain any definition of a service concession arrangement. However, it provides guidance on the common features of these arrangements. A typical ‘public to private’ service concession arrangement involves parties as described in the diagram below.


Grantor (who has the responsibility to provide public services, generally a government body or related entities/agencies)

Operator (a private sector entity constructing/upgrading and maintaining/operating the infrastructure used to provide public services such as roads, bridges, energy supply, etc.)

Public or ultimate customer (to whom the operator, directly or indirectly, provides services on behalf of the grantor)

Grant of a service concession arrangement to provide public services

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For the purpose of applicability of IFRIC 12 in the Indian context, the factors given in the table below need to be considered:

Sr. No Conditions as per IFRIC 12 Guidance under IFRIC 12 Factors to be considered

1 The grantor controls or regulates what kind of services the operator must provide with the infrastructure, to whom it must provide the same.

The control or regulation referred to in this condition could be by way of a contract or otherwise (such as through a regulator), and includes the circumstances in which the grantor buys all of the output as well as those in which some or all of the output is bought by other users. In applying this condition, the grantor and any other related parties shall be considered together. If the grantor is a public sector entity, the public sector as a whole, together with any regulators acting in public interest, shall be regarded as related to the grantor for the purposes of IFRIC 12.

In India, electricity generation and supply is highly regulated. The Electricity Act, 2003 lays down the laws relating to generation, transmission, distribution, trading, and the use of electricity. Electricity is a concurrent subject in List III of the Seventh Schedule in the Constitution of India. The Ministry of Power in India is primarily responsible for the development of electrical energy. Further, in India, it is quite common for companies to enter into long-term PPAs with government entities with a stipulation to sell all of the output to such entities including for power entities in the renewable energy sector e.g. solar energy or wind energy. In such situations, the relevant arrangements need to be carefully evaluated further for applicability of IFRIC 12.

2 At what price the services are to be provided.

For the purpose of this condition, the grantor does not need to have complete control of the price. It is sufficient for the price to be regulated by the grantor, contract or regulator, for example by a capping mechanism. However, the condition shall be applied to the substance of the agreement. Non-substantive features, such as a cap that will apply only in remote circumstances, shall be ignored. Conversely, if for example, a contract purports to give the operator freedom to set prices, but any excess profit is returned to the grantor, the operator’s return is capped and the price element of the control test is met with.

As per the Electricity Act, 2003, the Central Electricity Regulatory Commission or any other relevant State Electricity Regulatory Commission would determine the tariff in accordance with provisions of the Electricity Act for the supply of electricity by a generating company to a distribution licensee. For this purpose, the relevant commission may issue tariff orders on a time to time basis. Therefore, this condition seems to be fulfilled in case of arrangements where the prices are governed by tariff orders.

3 The grantor controls-through ownership, beneficial entitlement or otherwise- any significant residual interest in the infrastructure at the end of the term of the arrangement.

Infrastructure used in a public-to-private service concession arrangement for its entire useful life is within the scope of IFRIC 12. The grantor’s control over any significant residual interest should restrict the operator’s practical ability to sell or pledge the infrastructure as well as give the grantor a continuing right of use it throughout the period of the arrangement. The residual interest in the infrastructure is its estimated current value, as if it were already of the age and in the condition expected at the end of the period of the arrangement.

This is one of the conditions where a considerable judgement is required. In PPP arrangements, power plants are generally not owned by the grantors. Further, in practice, many of the PPAs may not contain clauses relating to handover of the plant by the operator to the grantor at the end of the tenure. However, it should be evaluated whether the arrangement is for the entire useful life of the asset since in such a case there would be no significant residual interest in the asset and the arrangement may fall within the purview of IFRIC 12 subject to fulfillment of other conditions. For this purpose, one needs to carefully evaluate various factors, including, the useful life of the asset, tenure of the PPA, termination and renewal clauses in the agreement, etc.

Applicability of IFRIC 12

An important step in accounting for service concession arrangements as per IFRIC 12 is to evaluate its applicability to the relevant arrangement. Many a times, it may not be straightforward since the evaluation involves significant judgement based on the nature and terms and conditions of these arrangements.

As a principle, IFRIC 12 applies to public-to-private service concession arrangements if:

a. the grantor controls or regulates what kind of services the operator must provide with the infrastructure, to whom it must provide the same, and at what price

b. the grantor controls - through ownership, beneficial entitlement or otherwise - any significant residual interest in the infrastructure at the end of the term of the arrangement.

IFRIC 12 applies to both, the infrastructure that the operator constructs or acquires from a third party for the purposes of the service arrangement and the existing infrastructure to which the grantor provides the operator access for the purposes of the service arrangement.


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It may be noted that the service concession arrangements may take various forms; and evaluation of each arrangement, including the terms and conditions of the PPAs is critical to conclude whether IFRIC 12 is applicable or not.

Accounting in case IFRIC 12 is applicable

In case IFRIC 12 becomes applicable, the accounting is comparatively complex and may require estimations with regard to relative fair values. IFRIC 12 provides that infrastructure within the scope of this interpretation would not be recognised as property, plant and equipment of the operator because the contractual service arrangement does not transfer the right to control the use of the public service infrastructure to the operator. The operator has access to operate the infrastructure to provide public service on behalf of the grantor in accordance with the terms specified in the contract.

IFRIC 12 further provides that under the terms of the contractual arrangements within its scope, the operator acts as a service provider. The operator constructs or upgrades infrastructure (construction or upgradation services) used to provide a public service and operates and maintains that infrastructure (operational services) for a specific period of time.

With regard to construction/upgradation services, the operator accounts for revenue and costs in accordance with the percentage of completion method as specified in IAS 11, Construction Contracts. With regard to revenue from operational and maintenance services, the revenue is recognised as the services are performed in accordance with IAS 18, Revenue. If the operator performs more than one service (i.e. construction/upgradation of services and operational services) under a single contract or arrangement, the consideration received or receivable would be allocated by referring to the relative fair values of the services delivered, when the amounts are separately identifiable. The fair value of the consideration for construction/upgradation services may be a right to a financial or an intangible asset. A financial asset is generally recognised when the grantor contractually guarantees to pay the operator specific or determinable amounts or the shortfall, if any, between amounts received from users of the public service and specific or determinable amounts. On the other hand, an intangible asset is recognised when the operator receives a right (a licence) to charge users of the public service which are contingent on the extent that the public uses the service. In the case of renewable energy entities, accounting under IFRIC 12 become challenging due to the nature of the

industry. It is because the quantum of energy that will be produced from either a solar or wind farm is not in the control of the operator. Therefore, the contractual terms of the agreement would have to be critically evaluated after taking into consideration all facts and circumstances to determine whether the right should be classified as an intangible asset or a financial asset.

Implication of following IFRIC 12

From the above, it is clear that the implications for an entity to which IFRIC 12 becomes applicable may be quite significant. For example, the infrastructure would not be recognised as property, plant and equipment of the operator but either as an intangible asset or as a financial asset. These implications may not only be limited to accounting but also extend to other aspects including financing, key financial ratios and their reporting to banks and other financial institutions on compliance with covenants, dividend payout and future projections. Accordingly, the relevant companies need to evaluate such arrangements carefully to conclude on the applicability of IFRIC 12 (or equivalent requirements under Ind AS), much before Ind AS becomes applicable to such companies.


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The diagram below summarises the accounting for service arrangements established by IFRIC 12:

(Source: IFRIC 12, issued by the International Accounting Standards Board)

Does the grantor control or regulate what services the operator must provide with the infrastructure, to whom it must provide them, and at what price?

Does the operator have a contractual right to receive cash or other financial asset from or at the direction of the grantor as described in paragraph 16 of the IFRIC 12?

Does the operator have a contractual right to charge users of the public services as described in paragraph 17 of the IFRIC 12?

Operator recognises an intangible asset to the extent that it has a contractual right to receive an intangible asset as described in paragraph 17 of the IFRIC 12.

Operator recognises a financial asset to the extent that it has a contratual right to receive cash or another financial asset as described in paragraph 16 of the IFRIC 12.

Does the grantor control, through ownership, beneficial entitlement or otherwise, any significant residual interest in the infrastructure at the end of the service arrangement? Or is the infrastructure used in the arrangement for its entire useful life?

Is the infrastructure constructed or acquired by the operator from a third party for the purpose of the service arrangement?

Is the infrastructure existing infrastructure of the grantor to which the operator is given access for the purpose of the service arrangement?

Outside the scope of the

interpretation

Outside the scope of the

interpretation (see paragraph 27 of the IFRIC

12)

No

No

No

No

Yes

Yes Yes

NoYes

YesYes

Within the scope of the interpretation

Operator does not recognise infrastructure as property, plant and equipment or as a leased asset.


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Embedded leases

Ind AS 17, Leases, Appendix C provides guidance on ‘determining whether an arrangement contains a lease’. This appendix does not apply to arrangements that are public-to-private service concession arrangements as discussed earlier.

According to Ind AS 17, an arrangement may contain a lease even though it is not in the legal form of a lease. For example, outsourcing arrangements may contain a lease of the underlying assets. The assessment of the substance of an agreement is carried out at its inception.

The assessment depends on whether:

• Fulfillment of the arrangement is dependent on the use of a specific asset or assets

The asset under the arrangement may be identified explicitly in the arrangement or it may be specified implicitly - e.g. if the supplier owns or leases only one asset with which he/she is to fulfil the obligation and it is not economically feasible or practicable for the supplier to use alternate assets to fulfil the arrangement.

• Arrangement conveys a right to use the asset(s)

If a buyer agrees to buy 100 per cent of the output of a specified asset and requires the asset to be operated at full capacity, then there is a strong presumption that the buyer has effective control over the asset and therefore that the arrangement contains a lease.

This presumption can be rebutted only when the operator, although it is obligated to operate at maximum capacity, retains significant operational flexibility to influence the profitability of the arrangement e.g. the mix of product quality/composition can be varied at the operator’s discretion.

Generally, under Ind AS 17 a buyer controls an asset and a lease exists when the buyer is taking substantially all of the output, because others cannot obtain the output from the specified asset. However, an exemption relating to arrangements in which the price is either contractually fixed per unit of output or equal to the market price per unit of output at the time of delivery, are not accounted for as leases. This exemption for fixed or market prices should be applied narrowly and only for arrangements in which the buyer clearly pays for the actual output.

Power sector entities may come under the purview of the embedded lease concept when they are either captive units to a large industrial house or have a power purchase agreement with a state electricity board subject to fulfillment of other conditions.

If an arrangement contains a lease, then the requirements of Ind AS 17 are applied only to the lease element of the arrangement. At the inception of such arrangement, payments required by the arrangement are split into lease payments and payments related to the other elements of the arrangement based on their relative fair values. In some cases, the separation of such payments will require the use of an estimation technique - e.g. with reference to a lease agreement for a comparable asset that contains no other elements or by estimating the payments for the other elements with reference to comparable agreements and then deducting these payments from total payments required. If it is impracticable to separate the lease payments, then:

i. if the lease arrangement is a finance lease, the lessee recognises an asset and a liability at an amount equal to the fair value of the asset that is identified as the subject of the lease; or

ii. if the lease arrangement is an operating lease, the lessee classifies all payments as lease payments in order to meet the disclosure requirements of Ind AS 17.

Implications

The power sector entities falling within the scope of embedded leases should carefully evaluate the implications of such classification. Property, plant and equipment would be classified either as finance or operating lease based on the criteria described in Ind AS 17. As explained in the IFRIC 12 implications, the impacts of lease classification would not just be limited to accounting but would also affect financing, key financial ratios, etc.

Accordingly, a power sector entity would have to carefully evaluate the terms and conditions in its contractual arrangement to conclude if they fall within the scope of embedded lease.

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Depreciation rate for electricity companiesThis article aims to:

– Highlight challenges faced by electricity companies in identifying an appropriate depreciation rate and computation of depreciation expense.

The provisions governing charge of depreciation in the erstwhile Schedule XIV to the Companies Act, 1956 (1956 Act) have been replaced with the Schedule II to the Companies Act, 2013 (2013 Act). While in Schedule XIV to the 1956 Act, certain minimum depreciation rates were prescribed, useful lives of the assets is the basis of depreciation as per the 2013 Act. Depreciation rates for electricity companies for tariff computation are notified by the Central Electricity Regulatory Commission (CERC)/State Electricity Regulatory Commission (SERC) (as applicable to a power sector entity). In this article, we have made an attempt to summarise some of the issues being faced by the power sector entities with respect to depreciation.

Depreciation rates - accounting vs regulatory

On 31 May 2011, the Ministry of Corporate Affairs (MCA) issued a General circular clarifying that depreciation charged under the Electricity Act, 2003 by companies governed by such Act was sufficient for the purpose of ensuring compliance to the Section 205 of the 1956 Act with respect to dividend declaration by such companies. The circular further attempted to take a clear position and acknowledged the tariff policy requirement to follow such rates of depreciation and the method of computing depreciation as notified by the CERC for the purpose of tariffs to be

used for accounting as well. This position was taken by the MCA on the basis that the statute governing such electricity companies i.e. the Electricity Act, 2003 being a special Act would override the provisions of the Companies Act. The 2013 Act concurs with the MCA position by incorporating specific provisions in Schedule II relating to depreciation of any specific asset notified for accounting purposes by a regulatory authority constituted under an Act of Parliament or by the Central Government.

The Schedule II to the 2013 Act lays down the indicative useful lives of plant and machinery used in generation, transmission and distribution of power. No such useful lives/depreciation rates were prescribed by the 1956 Act. The entities are allowed to follow different useful lives (as compared to useful lives laid down in the Schedule II to the 2013 Act) if an appropriate justification is given supported by a technical advice. However, the Schedule II to the 2013 Act explicitly states that the useful life or residual value of any specific asset, as notified for accounting purposes by a regulatory authority constituted under an Act of Parliament or by the Central Government should be applied in calculating the depreciation to be provided for such asset irrespective of the requirements of the Schedule II to the 2013 Act. As such, electricity companies are now required to follow such rates and method of computing depreciation as notified by the CERC/SERC (as applicable) for the purpose of tariffs as well as accounting.


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Differential depreciation method

The tariff structure for electricity companies largely consists of components such as return of equity, interest on loan capital, depreciation, interest on working capital, operation and maintenance expenses, etc. Typically, depreciation as per these regulations is calculated annually using the straight-line method using the rates specified in the respective regulations. To illustrate, the CERC Regulations, 2014 stipulate that depreciation should be calculated annually based on the straight-line method at specified rates (say 5.28 per cent for plant and machinery) for assets of the generating station and transmission system provided that the remaining depreciable value after a period of 12 years from the date of commercial operation of the station should be spread over the balance useful

life of the assets. The rationale behind following a differential depreciation method for tariff fixation is to ensure front-ending of enhanced cash flow through higher tariffs and further to avoid higher tax outflows during the initial years of the project.

Divergence from International practice

Internationally, a power and utility company is required to allocate the initial carrying amount of an item of property, plant and equipment into its significant parts or components, and depreciate each part separately. For each component the appropriate depreciation method, rate and the period needs to be considered. Whilst Schedule II to the 2013 Act also requires that useful life and depreciation for significant components of an asset be determined separately, due to the overriding provisions of

the statute and circular in relation to electricity companies, componentisation may not have been applied by a large number of Indian companies which fall under the regulation and consequently would have applied the tariff based depreciation rate.

To sum it up, when such companies prepare their financial statements under International standards, the areas of depreciation and componentisation requires careful consideration.

14

Accounting for rate regulated activitiesThis article aims to:

– Provide an overview of the principles on accounting for rate regulated activities. – Highlight key impacts on transition to Ind AS 114, Regulatory Deferral Accounts.

Some of the large public and private sector entities are involved in businesses that are regulated in one form or the other by a statute in India. Generally, price or rate regulation is provided for industries in which the general public is interested such as electricity, telecommunication, etc. Regulatory authorities are usually set up under a legislation in India which governs its constitution, powers, functions, etc. Regulation can take many forms depending upon the industry and the objectives to be achieved. Rate regulation is one of the main forms of guidelines which makes its presence felt in the power sector.

The need for accounting literature with respect to regulatory activities was felt and hence, the International Accounting Standards Board (IASB) issued IFRS 14, Regulatory Deferral Accounts on 30 January 2014. IFRS 14 provides interim guidance on accounting for regulatory deferral account balances for first-time adopters of IFRS while the IASB considers more comprehensive guidance on accounting for the effects of rate regulation.

On 18 February 2015, the Institute of Chartered Accountants of India (ICAI) issued a second edition of the guidance note on Accounting for Rate Regulated Activities (guidance note) which incorporates changes as compared to the first edition and makes it consistent with Ind AS 114, Regulatory Deferral Accounts (which corresponds to IFRS 14). The guidance note is effective from the financial year commencing 1 April 2015.

In India, the regulators such as the Central Electricity Regulatory Commission (CERC) and the State Electricity Regulatory Commission (SERC) govern the tariff that can be earned by certain power sector entities. This rate regulation in the power sector results in creation of a right (asset) or an obligation (liability). Therefore, this article highlights the accounting principles provided by the guidance note along with the implications of adopting Ind AS.

Scope of the guidance note

There are several methods of rate regulation such as cost-of-service regulation, price cap regulation or a hybrid mechanism. The guidance note only deals with effects on the entity’s financial statements. These effects are concerned with those operating activities that provide goods or services whose prices are subject to the cost-of-service regulation. Therefore, an entity should apply the guidance note only if it meets the following criteria:

• the regulator establishes the price that the entity can charge its customers

• the price is binding on the customers

• the price established is designed to recover the entity’s allowable costs of providing regulated goods or services and to earn a specified return.


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Activities of an entity which are subject to other forms of regulation are not covered by the guidance note. The guidance note provides the following examples of activities that do not fall under its purview:

• Activities that are subject to other forms of regulations (other than price regulations) such as the telecom sector in India which is covered by the Telecom Regulatory Authority of India.

• Where prices charged to customers by an entity are regulated through a ‘price cap’ i.e. an entity cannot charge more than the set prices. Though the prices are regulated and binding on the customers, however prices are not determined to recover the entity’s specific costs to provide the goods or services.

• Regulatory accounting where a regulatory entity maintains accounts in a form permitted by the regulator to obtain information needed for regulatory purposes.

• Where entities have both regulated and non-regulated activities, this guidance note applies to only those set of activities that meets the above criteria.

Regulatory assets and liabilities

• Regulatory asset A regulatory asset is an entity’s right to recover fixed or determinable amounts of money towards incurred costs as a result of the actual or expected actions of its regulator under the applicable regulatory framework.

A regulatory asset should be recognised when it is probable that the future economic benefits associated with it will flow to the entity as a result of the actual or expected actions of the regulator under the applicable regulatory framework and that the amount can be measured reliably. The probability criterion is said to be met with when there is reasonable assurance that future economic benefits will flow from the regulatory asset to the entity.

A regulatory asset can be recognised when the regulatory framework provides for the recovery of the incurred costs and that the entity has incurred such costs. If the recovery of the incurred costs is at the discretion of the regulator, the right can at best be considered a contingent asset, which would not be recognised till the approval of the regulator is received.

• Regulatory liability A regulatory liability is an entity’s obligation to refund or adjust fixed or determinable amounts of money as a result of actual or expected action of its regulator under the applicable regulatory framework.

In a cost-of-service regulation, the tariffs are subject to ‘truing up’ based on actual costs incurred and prudence checks by the regulator. If the costs incurred by the entity are lower than those initially considered for rate determination, the entity then has no other realistic alternative than to refund its customers. Similarly, if the tariffs are set assuming certain level of additions to the asset base and the actual additions made by the entity are lower, the entity would be required to refund a portion of the tariffs collected due to the lower additions to the asset base. The regulatory liabilities should be recognised in accordance with the recognition principles laid down in AS 29, Provisions, Contingent Liabilities and Contingent Assets.

By acknowledging the relevance of expected actions of the regulator, the guidance note is recognising the way that many existing rate – regulation schemes operate. For example, in some cases:

– an entity incurs costs and then submits a statement to the regulator for approval; or

– the regulator approves a rate to be charged over a period of time, which then is subject to revision.

Even though an approval generally takes several months, in several cases an entity may be able to make a reasonable estimate of the cost that might be approved by the regulator.

The entity’s expectation is generally based on historical actions taken, informal decisions made, and guidance and rules published by the regulator, in addition to some industry practices.

If the cost that an entity seeks to recover is of an unusual or one off nature, then unless the entity has received an in principle approval, it would need to make assumptions as to whether the regulator would approve these costs or not. This may be difficult and would involve the use of judgement.

Measurement

On initial recognition and at the end of each subsequent reporting period, an entity should measure a regulatory asset or regulatory liability at the best estimate of the amount expected to be recovered/refunded/adjusted as future cash flows under the regulatory framework. A regulatory asset or a regulatory liability should not be discounted to its present value.

Presentation

• In the balance sheet: Regulatory assets and regulatory liabilities are presented as current/non-current, as the case maybe, separately from other assets and liabilities. An entity should not offset the rate regulated assets and liabilities and should present separate line items in the balance sheet for the total of the regulatory assets and liabilities.

• In the statement of profit and loss: The net movement in all regulatory assets and regulatory liabilities for the reporting period is represented as a separate line item. Similarly, separate line item under tax expense needs to be given for the deferred tax expense/saving related to regulatory account balances.

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Disclosures

The guidance note requires detailed disclosures focussing on providing users of financial statements with the necessary information to evaluate the nature of, risk associated with, and the effects of rate regulation on an entity’s financial position, financial performance and cash flows.

In case an entity is subject to different regulators, detailed disclosures are required to be given for each set of operating activities.

It also requires reconciliation in a tabular format of the carrying amount in the balance sheet of the regulatory asset and regulatory liability to include certain prescribed components.

In case an entity derecognises regulatory assets and regulatory liabilities, it should disclose reasons for the same, a description of the operating activities affected and the amount of regulatory assets and regulatory liabilities derecognised.

An entity would apply the requirements of Ind AS 114 in its financial statements for subsequent periods if and only if, it has applied Ind AS 114 in its first Ind AS financial statements.

An entity that recognises regulatory deferral account balances on transition to Ind AS would subsequently be able to change its accounting policy to discontinue recognition of such balances, provided that the entity meets the criteria in Ind AS 8, Accounting Policies, Changes in Accounting Estimates and Errors i.e. the change would result in information that is reliable and more relevant.

However, a subsequent change in accounting policy to begin recognising regulatory deferral account balances might not be permitted.

Decision which could impact whether to continue with the recognition of regulatory deferral account balances

On transition to Ind AS, an entity that meets the scope requirements may opt to continue its existing practice of recognising and measuring regulatory deferral account balances based on its previous GAAP requirements. In arriving at a decision, an entity needs to consider various factors such as:

• whether or not it is possible to achieve a smooth transition to Ind AS

• judgement will be required in the measurement of regulatory deferral account balances

• impact of discontinuing the recognition of regulatory deferral account balances e.g. on financial ratios.

Entities applying Ind AS 114 may need to maintain multiple accounting records e.g. records that are based on:

• Ind AS, including separate presentations of all regulatory deferral account balances

• previous GAAP requirements, for measuring regulatory deferral account balances, and

• regulatory requirements, if any.

Transition to Ind AS 114

The following chart explains the transition to Ind AS 114 from the current GAAP:

Are the activities of the entity subject to rate regulation?

Is the entity adopting Ind AS for the first time?

Did the entity recognise regulatory deferral account balances in accordance with the local GAAP?

The entity may choose to continue recognition of regulatory deferral account balances

Ind AS 114 is not applicable

Yes

Yes

Yes

No

No

No


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Depending upon the regulatory requirements, there may be multiple level assurance requirements, which could increase the cost of reporting. Entities may, therefore, need to consider upgrading their accounting systems.

Implications on other Ind AS

• Ind AS 12, Income Taxes

The deferred tax on regulatory deferral account balances would be recognised in accordance with Ind AS 12 and would be included with the regulatory line items, instead of within the tax line items, with a clear disclosure. An entity may either present the deferred tax amount as a separate item alongside the regulatory deferral account balance or as a movement in regulatory deferral accounts or disclose it as a part of the required reconciliation of regulatory line items.

In some rate-regulatory schemes, the rate regulator permits or requires an entity to increase its future rates in order to recover some or all of the entity’s income tax expense. In such circumstances, this might result in the entity recognising a regulatory deferral account balance in the balance sheet related to income/deferred tax. A deferred tax expense/income would further arise pre-tax regulatory deferral account balances, and the resulting deferred tax would itself require additional regulatory deferral account balances. This interaction between deferred tax and regulatory deferral account balances would gross up the amount of both the regulatory deferral account balances and deferred tax.

• Ind AS 33, Earnings per Share (EPS)

An entity that is subject to rate regulation would be required to present its EPS, both including and excluding the movements in the regulatory deferral account balances, with equal prominence.

• Ind AS 36, Impairment of Assets

Impairment of regulatory deferral account balances is covered by the guidance note and Ind AS 114 also refers to the previous GAAP accounting policies for impairment of regulatory deferral account balances. Consequently, Ind AS 36 does not apply to separate regulatory deferral

account balances recognised. However, it might require an entity to perform an impairment test on a Cash-Generating Unit (CGU) that includes regulatory deferral account balances. In such cases, the regulatory deferral account balances would be treated in the same way as other specific items within the CGU that are excluded from the scope of Ind AS 36.

The recoverable amount of a CGU that provides a rate-regulated activity would be the same regardless of whether the entity recognises regulatory deferral account balances in its financial statements or not. This is because cash flow projections would include the future price effect of the rate regulation in both cases. As a result, applying the standard may affect the outcome of impairment testing. Including a regulatory deferral debit/credit account balance in the carrying amount of a CGU is likely to result in a larger/smaller impairment loss respectively.

As a result, if the impairment loss of the CGU is allocated against other assets within the CGU, then a larger/smaller impairment loss is likely to be recognised on those assets compared to an entity that does not apply the standard.

• Ind AS 110, Consolidated Financial Statements and Ind AS 28, Investment in Associates and Joint Ventures

Ind AS 110 states that a parent company would prepare consolidated financial statements using uniform accounting policies for like transactions and other events in similar circumstances. Further, Ind AS 114 states that if a parent company recognises regulatory deferral account balances in its consolidated financial statements in accordance with this standard, it must apply the same accounting policies to the regulatory deferral account balances arising in all of its subsidiaries, irrespective of whether the subsidiaries recognise those balances in their own financial statements. Similarly, adjustments may be made to the associate’s or joint venture’s accounting policies with respect to regulatory deferral account balances, conform to those of the investing entity in applying the equity method.

• Presentation

The regulatory account balances would be presented separately from assets, liabilities, income and expenses i.e. the standard does not permit grandfathering of presentation requirements, but requires separate line items of regulatory deferral account balances on the face of the primary financial statements.

Entities should consider the implications of these presentation requirements on their financial ratios and their reporting to banks and other financial institutions on compliance with covenants. Similarly, key performance indicators for internal reporting may need to be revisited.

(Source: Guidance note on accounting for rate regulated activities - Accounting and Auditing Update, May 2015

KPMG’s IFRS publication New on the Horizon: Accounting for rate regulated activities, May 2013)


Rate regulated entities should gear up to consider whether or not to adopt the accounting policy of rate regulated activities (as prescribed by the guidance note and then followed up by Ind AS 114 on the transition date). Entities should carefully analyse key impact areas such as requirement of judgement in measurement, maintenance of multiple accounting records, impact on other Ind AS, presentation and disclosure requirements, etc. before concluding on the accounting policy for rate regulated activities.

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Impact of GST on the power sectorThis article aims to:

– Provide an overview of the ‘Goods and Services Tax’ (GST) with respect to the power sector.

– Highlight related key impacts on the industry.

The central government together with the Empowered Committee of State Finance Ministers is actively working towards implementation of GST, which is expected to be a big tax reform that would affect companies in India. It is well-known that GST will subsume current indirect taxes imposed by the central/state governments such as excise duty, service tax, Value Added Tax (VAT) and entry tax. However, as per the latest report of the Select Committee on the Constitution (122) Amendment Bill, 2014, the power sector would be left out of the GST transformation1.

Presently, the generation and transmission of electricity is free from the incidence of indirect taxes. However, electricity duty is levied by states on consumption of electricity. On purchase of capital goods, inputs and input services required for use in the course of business operations, power producers/transmission utilities have to pay applicable indirect taxes. Such taxes paid on the procurement are not available as credit/set-off against electricity duty payable on the output.

Hence, indirect taxes typically become a part of the cost of operations and consequently, increase the cost of generation and transmission of power and ultimately impact end consumers.Under the proposed GST structure, consumption of electricity would continue to be subject to an electricity duty levied by the states1 while GST would have to be paid on procurement of capital goods, inputs and input services. This situation could lead to a cascading effect of taxes, much as in the present regime.

1. Report of the Select Committee on the Constitution (122) Amendment Bill, 2014 presented to the Rajya Sabha on 22 July, 2015 (See paragraphs 2.111 and 2.132)


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Expected increase in the tax cost of operations

The Task Force on GST set up by the Thirteenth Finance Commission, noted in its report that currently embedded taxes could possibly account for as high as 30 per cent of the cost of power production and distribution2. Further, since power is essential for any economic activity, the overall impact of such a tax inefficient regime is expected to be compounding.

Under the GST regime, it is expected that the tax cost of generation/distribution of power might significantly increase. Consequently, working capital requirements would also have to be reassessed. The following are expected to be key contributors towards the possible increase in tax cost of operations under the GST regime:

• Increase in tax on interstate procurements

Currently, interstate purchase of goods for generation and distribution of power are liable to Central Sales Tax (CST) at a concessional rate of 2 per cent against submission of Form C. Under GST, statutory forms and such concessions granted on the basis thereof, are expected to be discontinued. Consequently, it is likely that under GST interstate purchases would be taxed anywhere between 20 to 22 per cent3 plus 1 per cent additional tax4, instead of 14.5 per cent (excise duty of 12.5 per cent5 and CST of 2 per cent6 ) currently.

Similarly, exemption from CST on in transit sales (also available against specified statutory forms) is likely to be discontinued.

• Fate of exemptions unclear

Presently, various exemptions are available from excise duty and additional customs duties for goods supplied to certain power projects.

In certain cases, deemed export benefits are also allowed where excise duty is per se not exempt. Under GST, it is expected that exemptions will be limited and hence, the fate of the aforesaid exemptions is unclear. A removal of such exemptions could increase the tax cost of procurements since all input taxes would be added to the cost of operations.

• Increase in the rate at which services are taxed

The prevalent tax rate for services is 14 per cent; however under GST, the tax rate is expected to be anywhere in the range of 16 to 18 per cent7.

Looking towards GST for rationalisation

The Thirteenth Finance Commission had recommended that the power sector should be included in the GST base, with electricity duty being subsumed and power being treated at par with other goods8.

However, as mentioned in the beginning of this article the electricity duty is not being subsumed within GST.

If power is subject to GST (as an exercise of concurrent taxing power proposed in Article 246A of the Constitution), the cascading effect of taxes could be neutralised eventually bringing down the cost of power generation. This could in turn potentially benefit sectors for which power is an essential input. While stakeholders in the power sector might be desirous to see such rationalisation in the tax regime, developments in this space should be closely monitored so as to thoroughly assess the impact of GST.

2. Report of the Task Force on Goods & Services Tax, Thirteenth Finance Commission, 15 December, 2009 (See page 20, footnote 18)

3. There is no clarity currently on the exact standard GST rate. This is the range of tax rate estimated/expected by KPMG based on various sources. See para 3.55 of the Report of the Select Committee on the Constitution (122nd) Amendment Bill, 2014 wherein the Select Committee’s view has been expressed that standard GST rate should not go beyond 20 percent

4. Clause 18 of the Constitution (122 Amendment) Bill, 2014

5. Standard excise rate is assumed to be 12.5 per cent for the purpose of this example

6. Concessional rate of CST applicable against submission of Form C

7. There is no clarity currently on the exact GST rate for services. This is the range of tax rate estimated/expected by KPMG based on various sources

8. Chapter 5 of Thirteenth Finance Commission 2010-2015, Volume I: Report, December 2009


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Income Computation and Disclosure StandardsThis article aims to:

– Provide an overview of key areas of impact relating to the implementation of ICDS in the power sector.

The Ministry of Finance issued 10 ‘Income Computation and Disclosure Standards’ (ICDS) which prescribe a new framework for computation of taxable income by all assesses in relation to their income under the heads ‘Profit and gains from business or profession’ and ‘Income from other sources’. These standards are applicable for the assessment year 2016-17 (previous year 2015-16). With the adoption of ICDS, irrespective of whether the company reports its financial results as per Ind AS or the existing accounting standards under Indian GAAP, they would compute their taxable income in accordance with ICDS.

This article provides an overview of the significant impact areas in the power sector wherein differences exist between the current accounting and computation practices followed under the Accounting Standards (AS)as compared to the ICDS.

Borrowing costs

• Unlike AS 16, Borrowing Costs, the ICDS does not define any minimum period for classification of an asset as a qualifying asset (with the exception of the inventories). Borrowing costs, would need to be capitalised even if an asset does not take a substantial period of time to construct. For power sector companies, this difference may not be of much relevance as generally construction of a power plant takes a substantial period of time.

• In contrast to AS 16, exchange differences arising from foreign currency borrowings to the extent

that they are regarded as interest cost are not considered as borrowing cost under ICDS. ICDS reiterate the fact that capitalisation of exchange differences relating to fixed assets shall be in accordance with Section 43A of the Income Tax Act, 1961 (IT Act, 1961) and other similar provision of the IT Act, 1961.

• The ICDS has also prescribed a new formula for capitalisation of borrowing costs on general borrowings, which involves allocating the total general borrowing cost incurred in the ratio of average cost of qualifying assets on the first and the last day of the previous year (other than those assets which are directly funded out of specific borrowings). There is no specific formula prescribed by the current AS.

• The ICDS states that, in case of the specific borrowing, capitalisation of the borrowing cost should commence from the date of borrowing and in case of general borrowing, from the date of utilisation of such funds.

• As opposed to AS 16, the ICDS require capitalisation even if active development of a qualifying asset is interrupted.

• In addition under ICDS, income from temporary deployment of unutilised borrowed funds would not be deducted from the borrowing cost to be capitalised. Rather, the same would be treated as income.

There are no major GAAP differences between the AS and the Ind AS 23, Borrowing Costs.

Ind AS 23 states that borrowing costs may include interest expense calculated using the effective interest method as described in Ind AS 109, Financial Instruments whereas no such concept exists in the current AS 16.


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Government grants

• The ICDS does not permit the capital approach for recording of government grants; whereas according to AS 12, Government Grants, grants received for non-depreciable assets should be recognised under capital reserves. The ICDS requires that such grants should be treated as income.

• Under the ICDS, initial recognition of government grants cannot be postponed beyond the date of actual receipt even if all the recognition conditions according to AS 12 might not have been met with.

• Ind AS 23 addresses accounting treatment of specific transactions such as receipt of forgivable loans or government loans below the market

rate which are not covered in AS 12. However, no accounting guidance has been prescribed in the ICDS with respect to the aforesaid transactions.


Our comments The above provisions may not have a significant impact on the profit after tax of the companies (for companies which recognise deferred taxes). However, the provisions are expected to result in higher payment of taxes as the tax benefits associated with borrowing costs that are charged to the statement of profit and loss as per the AS 16 will be deferred over the years and can only be claimed as a depreciation charge (being a part of the block of fixed assets) in the tax computation in such years. This will lead to a significant difference between the written down value of fixed assets as per the books of account and as per the IT Act, 1961. Further, in many cases, tax expenses are part of the allowable costs calculated for tariff finalisation; in such cases an adequate consideration would need to be given for the aforesaid provisions at the time of tariff finalisation.

Our comments The power sector, especially the non-conventional energy sector has been offered various grants and incentives by the government in the recent past. Recognition of grants in the nature of promoters’ contribution or against non-depreciable assets are required to be considered as income and consequently are liable to income tax. Further, being an item of permanent difference, this can impact the profitability of companies. The additional tax payment on such grants may be considered during the time of tariff finalisation where income taxes are considered as allowable costs.

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Provisions, contingent liabilities and contingent assets

• Unlike in the existing standard, the ICDS requires recognition of provision only if it is ‘reasonably certain’. It excludes from its ambit onerous contracts.

• In addition, the ICDS also requires recognition of contingent assets when the inflow of economic benefits is reasonably certain.

• These changes presumably have been made with the intention to bring in consistency in the tax treatment of losses and gains.

• Unlike AS 29, Provisions, Contingent Liabilities and Contingent Assets

and the ICDS, Ind AS 37, Provisions, Contingent Liabilities and Contingent Assets requires provision for constructive obligations. It further states that, contingent assets are required to be disclosed in the financial statements when an inflow of economic benefits is probable.

One area that needs the regulator’s attention is Minimum Alternate Tax (MAT) provisions. Once Ind AS comes in, some companies would report financial results based on Ind AS whereas others would report based on existing Indian GAAP; therefore, the accounting profits based on which MAT is to be calculated would need to be clarified, and may require consideration of suitable adjustments to Ind AS accounting profit.

The ICDS is applicable for the previous year 2015-16 and companies need to gear up for the change. While there is no requirement for maintenance of an additional set of books of account for ICDS, additional records and reconciliations of the differences between AS and the ICDS might have to be prepared by the companies. The entities should carry out an impact assessment and based on such assessment, frame an appropriate plan for the implementation of ICDS.


Our comments Contingent assets disclosed in the financial statements in accordance with Ind AS 37 could have tax implications. Taxation of movements in regulatory assets/liabilities recognised in the statement of profit and loss in accordance with the guidance note on Accounting for Rate Regulated Activities/Ind AS 114, Regulatory Deferral Accounts, might also come under the scanner of the income tax authorities based on the provisions of the ICDS.

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Accounting for government grants by companies in the renewable energy industryThis article aims to:

– Highlight key accounting considerations for companies operating in the renewable energy industry with respect to government grants.

India has one of the largest electricity generation capacities in the world and the power sector in the country is highly diverse with varied commercial sources for power generation. The demand for power has been growing at a rapid rate and outstripped supply over the years, resulting in power shortages.

Renewable energy presently forms a small part of the overall installed capacity in India, but power generation from renewable sources is on the rise and the untapped market potential for overall renewable energy in India is significant.

This article analyses some of the accounting issues for companies operating in this industry. It considers currently effective standards (Indian GAAP) and notes future developments (Ind AS) that could impact accounting.

Whilst the reasons for increase in renewable power sources could be both social and financial, some of the key financial reasons have been government support, increasing cost competitiveness due to technological innovation and an increased demand for equipment which have led to economies of scale in manufacturing and deployment.

Accounting for government grants

Traditionally many companies operating in the renewable energy sector have been dependent on government subsidies in order to enable them to compete with the traditional fossil fuel energy companies. These grants may be in different forms such as subsidised cost of assets, Renewable Energy Certificates (RECs), incentives for exceeding normative capacity, borrowings at subsidised interest rates, etc.

AS 12, Accounting for Government Grants, is the governing literature for all government grant transactions under Indian GAAP. Appropriate accounting of government grants by an entity is important to bring out the impact of such grants on the results of the entity during the reporting period.

As per AS 12, government grants should not be recognised until there is reasonable assurance that the entity would comply with the conditions attached to the grants, and that the grants would be received.

Two broad approaches may be followed for the accounting treatment of government grants:

• the capital approach, under which a grant is treated as part of the shareholders’ funds, and

• the income approach, under which a grant is taken to income over one or more periods.

It is generally considered appropriate that accounting for government grant should be based on the nature of the relevant grant.


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In the above mentioned example of grants given in energy sector, the government may subsidise the cost of assets in many different ways. These grants related to specific fixed assets, should be netted-off from the gross value of the assets. The grant is thus recognised in the statement of profit and loss over the useful life of depreciable asset by way of a reduced depreciation charge. Where the grant related to a specific fixed asset equals the whole or virtually the whole of the cost of the asset, then the asset should be shown in the balance sheet at a nominal value. Alternatively, government grants related to depreciable fixed assets may be treated as deferred income which should be recognised in the statement of profit and loss over the periods and in the proportion in which depreciation on related assets is charged.

Grants related to non-depreciable assets should be credited to capital reserve under this method as there is usually no charge to income in respect of such assets. However, if a grant related to a non-depreciable asset requires the fulfillment of certain obligations, the grant should be credited to income over the same period over which the cost of meeting such obligations is charged to income.

Government grants related to revenue e.g. RECs, incentives for exceeding normative capacity, etc. should be recognised on a systematic basis in the statement of profit and loss over the periods necessary to match them with the related costs, which they are intended to compensate. Such grants should either be shown separately under ‘other income’ or deducted in reporting the related expense.

Government grants of the nature of promoters’ contribution should be credited to the capital reserve and treated as a part of shareholders’ funds.

Government grants in the form of non-monetary assets, given at a concessional rate, should be accounted for on the basis of their acquisition cost. In case, a non-monetary asset is given free of cost, it should be recorded at a nominal value.

Government grants that are receivable as compensation for expenses or losses incurred in a previous accounting period or for the purpose of providing immediate financial support to the entity with no further related costs, should be recognised and disclosed in the statement of profit and loss of the period in which they are receivable, as an extraordinary item, if appropriate.

Position under Ind AS 20, Accounting for Government Grants and Disclosure of Government Assistance

Promoters’ contributionUnlike AS 12, the concept of promoters’ contribution does not exist under Ind AS 20.

Borrowings at subsidised interest ratesWhilst instances of subsidised interest rates on borrowing by companies in the renewable energy industry is a fairly common phenomenon, there is no specific guidance for the same under AS 12. As per Ind AS 20, the benefit of a government loan at a below market rate of interest is treated as a government grant. The loan would be recognised and measured in accordance with Ind AS 109, Financial Instruments. The benefit of a below-market rate of interest shall be measured as the difference between the initial carrying value of the loan determined in accordance with Ind AS 109 and the proceeds received therein. The benefit is accounted for in accordance with Ind AS 20. The entity shall consider the conditions and obligations that have been, or should be, met with when identifying the costs for which the benefit of the loan is intended to compensate.

First time adoption of Ind AS 20

A first-time adopter would have to classify all government loans received as a financial liability or an equity instrument in accordance with Ind AS 32, Financial Instruments: Presentation. Except as permitted by para B11 of Ind AS 101 (given below), a first-time adopter would apply the requirements in Ind AS 109, Financial Instruments, and Ind AS 20 prospectively to government loans existing at the date of transition to Ind AS and would not recognise the corresponding benefit of the government loan at a below-market rate of interest as a government grant. Consequently, if a first-time adopter did not, under its previous GAAP, recognise and measure a government loan at a below-market rate of interest on a basis consistent with Ind AS requirements, it would use its previous GAAP carrying amount of the loan at the date of transition to Ind AS as the carrying amount of the loan in the opening Ind AS balance sheet. An entity would apply Ind AS 109 to the measurement of such loans after the date of transition to Ind AS.

Despite the above requirement, an entity may apply the requirements in Ind AS 109 and Ind AS 20 retrospectively to any government loan originated before the date of transition to Ind AS, provided that the information needed to do so had been obtained at the time of initially accounting for that loan (para B11 of Ind AS 101) .

Significant variations between AS 12, Ind AS 20 and IAS 20

Ind AS 20 requires measurement of non-monetary grants only at their fair value as against the acquisition cost as required by AS 12. Fair value as per Ind AS 20 is the price at that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. This incidentally is also one of the carve outs from IFRS where IAS 20 , Accounting for Government Grants and Disclosure of Government Assistance gives an option to measure non-monetary government grants either at their fair value or at nominal value.

Another significant carve-out from IFRS is where IAS 20 gives an option to present the grants related to assets, including the non-monetary grants at a fair value in the balance sheet, either by setting up the grant as deferred income or by deducting the same while arriving at the carrying amount of the asset. A similar option is also available under AS 12; however, the option to present such grants by deduction of the grant in arriving at the carrying amount of the asset is not available under Ind AS 20. This carve-out is expected to have significant impact on the power sector entities. For example, for certain power sector entities, customs duty could have been waived off by the government on import of property, plant and equipment. If those entities have exercised the option of deducting the amount of waiver from the carrying amount of the fixed asset, then on transition to Ind AS, this accounting policy could lead to huge challenge if the entity selects deemed cost exemption for property, plant and equipment. This is due to the fact that such entities would separate such customs duty waiver as a deferred revenue out of the retained earnings on transition to Ind AS.

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Borrowing cost in the power sectorThis article aims to:

– Summarise the issues relating to capitalisation of borrowing costs in the power sector.

Capitalisation of borrowing costs as per Accounting Standard (AS) 16, Borrowing Costs, is an area which requires application of judgement and understanding of facts and circumstances in each case. The delay in commissioning/declaration of date of commercial operation by various power generating companies in the recent past, has only made the matter more relevant and a point of focus for such companies.

Technical literature

As per AS 16, borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset should be capitalised as part of the cost of that asset. The capitalisation should commence when expenditure for the acquisition, construction or production of the qualifying asset and the borrowing costs are being incurred and activities that are necessary to prepare the asset for its intended use or sale are in progress. Capitalisation of borrowing costs should be suspended during extended periods in which active development is interrupted; however, it should not be suspended when a temporary delay is essential for getting an asset ready for its intended use or sale.

Issues faced by the power sector

The power sector in India had been facing uncertainties due to reasons such as delayed resolution of last-mile connectivity, issues relating to coal procurement and the non-availability of gas supply for gas-based plants. This uncertainty leads to challenges in capitalisation of borrowing costs. These reasons appear to be beyond the realm of control of any power company and are leading to delays in the process of getting an asset ready for its intended use.

Another practical issue faced by companies relates to the capitalisation of power projects/wind farm comprising of various plants/units (e.g. 10 units of 500MW each for a power project of 5,000MW) which can operate and generate electricity independent of each other. AS 16 states that when the construction of a qualifying asset is completed in parts and a completed part is capable of being used while construction continues for the other parts, capitalisation of the borrowing costs in relation to that part should cease when substantially all the activities necessary to prepare that part for its intended use or sale are complete. The key point for consideration is whether capitalisation of borrowing costs should cease on completion of the individual unit/plant or the entire project.


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Clarification issued by the Ministry of Corporate Affairs (MCA)

The power sector made a representation to the MCA and the Institute of Chartered Accountants of India (ICAI) to allow capitalisation of borrowing costs in the aforesaid situations. The MCA issued a clarification on 27 August 2015 on the issue of capitalisation of borrowing costs. As per the clarification issued by the MCA:

• Costs incurred during the extended delay in commencement of commercial production after the plant is otherwise ready does not increase the worth of the fixed asset. Such costs therefore cannot be capitalised.

• In case, one of the units of the project is ready for commercial production and is capable of being used while construction continues for the others, capitalisation of costs should cease in relation to that part once it is ready for commercial production.

Next steps

On the basis of the above guidance, the power companies may need to carefully evaluate the expenses incurred during the periods of delays and segregate them from the expenses necessary for getting other assets ready for its intended use or sale. Further, a process for identification of completed parts also needs to be developed by the power companies to identify those completed parts that can operate independently while the balance is still under construction.

A related issue to borrowing costs is the accounting under Income Computation and Disclosure Standards (ICDS). This topic has been discussed in the article on ICDS in this publication.


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Regulatoryupdates


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The MCA amends rules related to acceptance of deposits

The Ministry of Corporate Affairs (MCA), through a notification dated 15 September, 2015 amended certain provisions of the Companies (Acceptance of Deposits) Rules, 2014. The amended rules are called Companies (Acceptance of Deposits) Second Amendment Rules, 2015.

Current GuidanceCurrently, the term ‘deposit’, inter alia, excludes any amount received from a person who, at the time of receipt of such an amount, was a director of the company. However, amount received from a director would be excluded from the ambit of ‘deposits’ if the director from whom money is received, furnishes to the company at the time of giving the money, a declaration in writing that the amount is not being given out of the funds acquired by him by borrowing or accepting loans or deposits from others.

Amendment to RulesUnder the amended Rules, ‘deposit’, inter alia, excludes any amount received from a person who at the time of the receipt of the amount, is a director of the company or a relative of the director of the private company.

However, an amount received from a director of the company or a relative of the director of the private company, as the case may be, would be excluded from the ambit of ‘deposits’ if the director of the company or relative of the director of the private company from whom money is received, furnishes to the company at the time of giving the money, a declaration in writing that the amount is not being given out of funds acquired by him by borrowing or accepting loans or deposits from others.

Additionally, the company would be required to disclose the details of the money so accepted in the board’s report. (Emphasis added to present changes)

Increase in base for accepting deposits

Current requirementsFor companies accepting deposits from members under Section 73(2) of the Companies Act, 2013 (2013 Act)

Currently, no company can accept or renew deposits which are repayable on demand or upon receiving a notice within a period of less than six months or more than 36 months from the date of acceptance or renewal of such deposit.

However, for the purpose of meeting any of its short-term requirements of funds, a company may accept or renew such deposits for repayment earlier than six months from the date of deposit or renewal provided that:

• such deposits should not exceed 10 per cent of the aggregate of the paid-up share capital and free reserves of the company, and

• such deposits are repayable not earlier than three months from the date of such deposits or renewal thereof.

Also, no company (referred under Section 73(2) of the 2013 Act) is allowed to accept or renew any deposit from its members, if the amount of such deposits together with the amount of other deposits outstanding as on the date of acceptance or renewal of such deposits exceeds 25 per cent of the aggregate of the paid-up share capital and free reserves of the company.

For eligible companies (covered under Section 76 of the 2013 Act)

• The Rules define ‘eligible company’ to mean a public company

– having a net worth of not less than INR100 crore or a turnover of not less than INR500 crore and

– which has obtained the prior consent of the company in the general meeting by means of a special resolution and also filed the said resolution with the Registrar of Companies before making any invitation to the public for acceptance of deposits.

• Currently, no eligible company can accept or renew:

a. any deposit from its members, if the amount of such deposit together with the amount of deposits outstanding as on the date of acceptance or renewal of such deposits from members exceeds 10 per cent of the aggregate of the paid-up share capital and free reserves of the company

b. any other deposit, if the amount of such deposit together with the amount of such other deposits, other than the deposit referred to in clause (a), outstanding on the date of acceptance or renewal exceeds 25 per cent of aggregate of the paid-up share capital and free reserves of the company.

Amendment to RulesFor companies accepting deposits from members under Section 73(2) of the 2013 Act

• The amended Rules have increased the base for acceptance of deposits.

• Accordingly, now the Rules state that a company may accept or renew deposits earlier than six months from the date of deposit or renewal for the purpose of meeting any of its short-term requirements provided that:

a. such deposits should not exceed 10 per cent of the aggregate of the paid-up share capital, free reserves and securities premium account of the company, and

b. such deposits are repayable not earlier than three months from the date of such deposits or renewal thereof.

• Similarly, no company (referred under Section 73(2) of the 2013 Act) is allowed to accept or renew any deposit from its members, if the amount of such deposits together with the amount of other deposits outstanding as on the date of acceptance or renewal of such deposits exceeds 25 per cent of the aggregate of the paid-up share capital, free reserves and securities premium account of the company.

(Emphasis added to present changes)

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For eligible companies (covered under Section 76 of the 2013 Act)

The amended Rules now provide that no eligible company can accept or renew.

a. any deposit from its members, if the amount of such deposit together with the amount of deposits outstanding as on the date of acceptance or renewal of such deposits from members exceeds 10 per cent of the aggregate of the paid-up share capital, free reserves and securities premium account of the company

b. any other deposit, if the amount of such deposit together with the amount of such other deposits, other than the deposit referred to in clause (a), outstanding on the date of acceptance or renewal exceeds 25 per cent of aggregate of the paid-up share capital, free reserves and securities premium account of the company.

(Emphasis added to present changes)

(Source: MCA notification dated 15 September 2015)

The RBI recommends a road map for implementation of Ind AS for banks and NBFC

Background

On 16 February 2015, MCA issued the Companies (Indian Accounting Standards) Rules, 2015 which lays down a road map for companies other than insurance, banking companies and Non-Banking Financial Companies (NBFCs) for implementation of Ind AS (converged with the International Financial Reporting Standards (IFRS)) in a phased manner starting from 1 April 2016. Currently, Ind AS for corporates is under implementation.

New development

On 29 September 2015, the Reserve Bank of India (RBI) through its Fourth Bi-monthly Monetary Policy Statement, 2015-16 informed the stakeholders that it has recommended to the MCA a road map for the implementation of Ind AS for banks and NBFCs from 2018-19 onwards.

Next steps

The RBI has constituted a working group (Chairman: Shri Sudarshan Sen) for its implementation. The report of this working group will be uploaded on RBI’s website by the end of October 2015 for public comments. A detailed road map would be issued thereon.

(Source: RBI Fourth Bi-monthly Monetary Policy Statement, 2015-16 dated 29 September 2015 and KPMG’s First Notes: RBI recommends a road map for implementation of Ind AS for banks and NBFCs dated 30 September 2015)

Companies (Filing of Documents and Forms in Extensible Business Reporting Language) Rules, 2015

The MCA, through a notification dated 9 September 2015, issued the Companies (Filing of Documents and Forms in Extensible Business Reporting Language) Rules, 2015 which inter alia requires certain class of companies to file their financial statements and other documents under Section 137 of the Companies Act, 2013 with the Registrar in e-form AOC-4 XBRL given in Annexure I of these Rules for the financial year commencing on or after 1 April 2014 using the XBRL taxonomy given in Annexure II, namely:

i. all companies listed with any stock exchange(s) in India and their Indian subsidiaries

ii. all companies having paid-up capital of INR5 crore or above

iii. all companies having turnover of INR100 crore or above

iv. all companies which were hitherto covered under the Companies Filing of Documents and Forms in in Extensible Business Reporting Language) Rules, 2011.

The companies in banking, insurance, power sector and NBFCs are exempted from XBRL filing.

The above notification will be effective from the date of its publication in the Official Gazette.

(Source: MCA notification dated 9 September 2015)

Format for compliance report on corporate governance

On 2 September 2015, the Securities and Exchange Board of India (SEBI) issued the SEBI (Listing Obligations and Disclosure Requirements) Regulations, 2015 (Listing Regulations). Clause 27(2) of the Listing Regulations requires listed entities to submit quarterly compliance report on corporate governance in the format specified by SEBI from time to time to recognised stock exchange(s) within 15 days from close of the quarter. SEBI in accordance with the above clause prescribe formats for compliance report through a circular dated 24 September 2015. The listed entities are required to submit prescribed Annexures I, II and III.The timelines prescribed by the circular are:

Annexure - I - on a quarterly basis;

Annexure - II - at the end of the financial year (for the whole of financial year);

Annexure - III - within six months from the end of the financial year. This may be submitted along with second quarter report.

Additionally, as per Clause 17(3), following reports should also be placed before the board of directors of the listed entity:

a. Compliance Reports

b. Secretarial Audit Report prepared in accordance with Rule 9 of Companies (Appointment and Remuneration of Managerial Personnel) Rules, 2014 under Section 204 of the Companies Act, 2013 in so far as it pertains to Securities Laws.

The above mentioned circular would come into force with effect from 90 days from notification of the Listing Regulations.

The SEBI through its circular has increased the reporting requirements for listed entities.

(Source: Circular CIR/CFD/CMD/5/2015 dated 24 September 2015 by SEBI)

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The ICAI issues exposure drafts on Ind AS

The MCA through its notification dated 16 February 2015 issued 39 Indian Accounting Standards (Ind AS) which are converged with IFRS. The IFRS

converged standards are expected to bridge the significant gaps that exist in current accounting guidance in India.

Recently, the Institute of Chartered Accountants of India (ICAI) issued following Exposure Drafts:


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Name of the ED Topics covered

Ind AS 11, Constructions Contracts(Issued on 25 September 2015)

• Accounting for construction contracts in the financial statements of contractors including the financial statements of real estate developers

• Service concession arrangements

• Service concession arrangements: Disclosures.

Ind AS 18, Revenue(Issued on 25 September 2015)

• Accounting for revenue arising from the following transactions and events:

– sale of goods – rendering of services – use by others of entity assets yielding interest and royalties.

• Revenue – Barter Transactions Involving Advertising Services

• Customer Loyalty Programmes

• Transfer of Assets from Customers.

Ind AS 105, Non-current Assets Held for Sale and Discontinued Operations (Issued on 25 September 2015)

Changes in methods of disposal.

Ind AS 107, Financial Instruments: Disclosures (Issued on 25 September 2015)

Applicability of the amendments to Ind AS 107 to condensed interim financial statements.

Ind AS 19, Employee Benefits (Issued on 25 September 2015) Discount rate: regional market issue.

Ind AS 34, Interim Financial Reporting (Issued on 25 September 2015)

Disclosure of information ‘elsewhere in the interim financial report’.

Ind AS 110, Consolidated Financial Statements (Issued on 25 September 2015)

Scope included investment entities exemption.

Ind AS 112, Disclosure of Interests in Other Entities (Issued on 25 September 2015)


Ind AS 28, Investments in Associates and Joint Ventures (Issued on 25 September 2015)


Ind AS 101, First-time Adoption of Indian Accounting Standards (Issued on 25 September 2015)


Ind AS 17, Leases (Issued on 22 September 2015) Exception to straight lining.

Ind AS 1, Presentation of Financial Statements(Issued on 22 September 2015)

Clarification on information to be disclosed.

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The ICAI issued the EDs with a view to develop Ind AS in line with the amended paragraphs. We have highlighted the key amendments introduced by the respective EDs.

Ind AS 11, Construction Contracts and Ind AS 18, Revenue

The principles in the ED on revenue are based on the principles of IAS 18, Revenue.

Overall approachThe overall approach of the standard is as follows:

• Revenue would be recognised only if it is probable that future economic benefits would flow to the entity and those benefits can be measured reliably.

• Revenue recognition would not require cash consideration. However, when goods or services exchanged are similar in nature and value, the transaction would not generate revenue.

• When an arrangement includes more than one component, it may be necessary to account for the revenue attributable to each component separately.

• When two or more transactions are linked so that the individual transactions have no commercial effect on their own, they would be analysed as one arrangement.

Measurement

• Revenue would be measured at the fair value of the consideration received, taking into account any trade discount, volume discount or cash discount.

Ind AS 110, Consolidated Financial Statements

Ind AS 110 establishes principles for the presentation and preparation of consolidated financial statements when an entity controls one or more other entities.

• An investment entity which measures its subsidiaries at fair value through profit or loss are exempt from application of Ind AS 110.

• The investment entity has a subsidiary that is not an investment entity and whose main purpose and activities are providing services that relate to the investment entity’s investment

activities, shall consolidate that subsidiary in accordance with Ind AS 110.

Ind AS 112, Disclosure of Interests in Other Entities

• An investment entity that prepares financial statements in which all of its subsidiaries are measured at fair value through profit or loss in accordance with Ind AS 110 shall present the disclosures relating to the investment entities required by Ind AS 112.

Ind AS 28, Investments in Associates and Joint Ventures

• Entities that measure investment in the subsidiary at fair value through profit and loss are exempt from applying the equity method under Ind AS 28.

• If an entity has an interest in an associate or joint venture that is an investment entity, the entity may, when applying the equity method, retain the fair value measurement applied by that investment entity associate or joint venture to the investment entity associate’s or joint venture’s interests in the subsidiaries.

Ind AS 105, Non-current Assets Held for Sale and Discontinued Operations

Ind AS 105 specifies the accounting for assets held for sale and the presentation and disclosure of discontinued operations.

The ED on Ind AS 105 states that, if an entity reclassifies an asset (or disposal group) directly from being held for sale to being held for distribution to owners, or directly from being held for distribution to owners to being held for sale, then the change in classification is considered a continuation of the original plan of disposal. The entity:

a. should not follow the guidance given for non-current assets (or disposal group) that ceases to be classified as held for sale or held for distribution to owners to account for this change. The entity shall apply the classification, presentation and measurement requirements in this Ind AS that are applicable to the new method of disposal.

b. should measure the non-current asset (or disposal group) by following the requirements in

paragraph 15 (if reclassified as held for sale) or 15A (if reclassified as held for distribution to owners) and recognise any reduction or increase in the fair value less costs to sell/costs to distribute of the non-current asset (or disposal group) by following the requirements given for the recognition of impairment losses and reversals.

c. should not change the date of classification in accordance with guidance given in Ind AS 105. This does not preclude an extension of the period required to complete a sale or a distribution to owners if the conditions given in paragraph 9 of Ind AS 105 are met with.

Ind AS 107, Financial Instruments: Disclosures

Ind AS 107 require entities to provide disclosures in their financial statements that enable users to evaluate:

a. the significance of financial instruments for the entity’s financial position and performance; and

b. the nature and extent of risks arising from financial instruments to which the entity is exposed during and at the end of the reporting period, and how the entity manages those risks.

Further, principles in this Ind AS complement the principles for recognising, measuring and presenting financial assets and liabilities in Ind AS 32, Financial Instruments: Presentation, and Ind AS 109, Financial Instruments.

The ED on Ind AS 107 states that when an entity transfers a financial asset, it may retain the right to service that financial asset for a fee that is included in, for example, a servicing contract. The entity assesses the servicing contract in accordance with the guidance given in paragraphs 42C and B30 to decide whether the entity has continuing involvement as a result of the servicing contract for the purposes of disclosure requirements. For example, a servicer will have continuing involvement in the transferred financial asset for the purposes of the disclosure requirements if the servicing fee is dependent on the amount or timing of the cash flows collected from the transferred financial asset.

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Ind AS 19, Employee Benefits

The objective of this standard is to prescribe the accounting and disclosure requirements for employee benefits.

Ind AS 19 provides for the actuarial assumptions to be used while ascertaining discount rate. As per Ind AS 19, the rate used to discount post-employment benefit obligations (both funded and unfunded) shall be determined by reference to market yields on government at the end of the reporting period.

In this respect, the ED on Ind AS 19 provides that while calculating the discount rate for currencies other than the Indian National Rupee for which there is a deep market in high quality corporate bonds, the market yields (at the end of the reporting period) on such high quality corporate bonds denominated in that currency shall be used. Further, the currency and term of the government or corporate bonds shall be consistent with the currency and estimated term of the post-employment benefit obligations.

Ind AS 34, Interim Financial Reporting

The objective of this standard is to prescribe the minimum content of an interim financial report and to prescribe the principles for recognition and measurement in complete or condensed financial statements for an interim period. Timely and reliable interim financial reporting improves the ability of investors, creditors, and others to understand an entity’s capacity to generate earnings and cash flows along with its financial condition and liquidity.

Ind AS 34 requires that interim financial statements should disclose significant events and transactions in the notes to its interim financial statements, if not disclosed elsewhere in the report. The ED on Ind AS 34 clarifies that disclosures shall be given either in the interim financial statements or incorporated by cross reference from the interim financial statements to some other statement (such as management commentary or risk report) that is available to users of the financial statements on the same terms as the interim financial statements and at the same time. If the users of these financial statements do not have

access to the information incorporated by cross-reference on the same terms and at the same time, the interim financial report is said to be incomplete.

Ind AS 101, First-time Adoption of Indian Accounting Standards

Ind AS 101 is applicable for entities in their first Ind AS financial statements and each interim financial report, if any, that they presents in accordance with Ind AS 34, Interim Financial Reporting, for part of the period covered by their first Ind AS financial statements. The ED brought an amendment to this Ind AS by excluding investment property from the preview of valuation at fair value since an investment property is accounted for in accordance with Ind AS 40, Investment Property which permits only cost model approach. As a consequence, paragraph 30 of Ind AS 101 is amended and paragraph D7(a) is deleted.

Ind AS 17, Leases

The objective of this standard is to prescribe, for lessees and lessors, the appropriate accounting policies and disclosure to apply in relation to leases.

The ED on Ind AS 17 brought about a clarification regarding straight lining of lease rentals in case of an operating lease for ease of reference. Paragraphs 34A and 51A have been added which provide that where the escalation of lease rentals is in line with the expected general inflation so as to compensate the lessor for an expected inflationary cost, the increases in the rentals may not be straight lined.

Ind AS 1, Presentation of Financial Statements

This Standard prescribe the basis for presentation of general purpose financial statements to ensure comparability both with the entity’s financial statements of previous periods and with the financial statements of other entities. It sets out overall requirements for the presentation of financial statements, guidelines for their structure and minimum requirements for their content.

The ED brought an amendment by introducing the following paragraphs:

Para 30 A - When applying this and other Ind AS an entity shall decide, taking into consideration all relevant facts and circumstances, how it aggregates information in the financial statements, which include the notes. An entity shall not reduce the understandability of its financial statements by obscuring material information with immaterial information or by aggregating material items that have different natures or functions.

Para 31 - Some Ind AS specify information that is required to be included in the financial statements, which includes the notes. An entity need not provide a specific disclosure required by an Ind AS if the information resulting from that disclosure is not material except when required by law. This is the case even if the Ind AS contains a list of specific requirements or describes them as minimum requirements. An entity shall also consider whether to provide additional disclosures when compliance with the specific requirements in Ind AS is insufficient to enable users of financial statements to understand the impact of particular transactions, other events and conditions on the entity’s financial position and performance.

Ind AS 1 requires an entity to present additional line items, headings and subtotals in the balance sheet when such presentation is relevant to an understanding of the entity’s financial position. ED on Ind AS 1 provides further guidance on presentation of subtotals.

The ED also brought an amendment to the information to be presented in the other comprehensive income section of the statement of profit and loss.

Ind AS 1 requires presentation of notes to financial statements in a systematic manner. The ED on Ind AS 1 further provides that an entity shall consider the effect on the understandability and comparability of its financial statements while determining a systematic manner.Examples of systematic ordering or grouping of the notes have also been provided in the ED.

(Source: ICAI Exposure drafts issued in September

2015)

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KPMG in India’s IFRS institute KPMG in India is pleased to re-launch its IFRS institute - a web-based platform, which seeks to act as a wide-ranging site for information and updates on IFRS implementation in India.The website provides information and resources to help board and audit committee members, executives, management, stakeholders and government representatives gain insight and access to thought leadership publications that are based on the evolving global financial reporting framework.

ICAI releases revised guidance on Internal Financial Controls Over Financial Reporting

16 September 2015

Under Section 143(3)(i) of the Companies Act, 2013 (2013 Act), an auditor is required to state in their audit report whether the company has an adequate internal financial controls (IFC) system in place and the operating

effectiveness of such controls. Explanation to Section 134(5)(e) of the 2013 Act defines IFC to include policies and procedures adopted by the company for ensuring orderly and efficient conduct of its business, accuracy and completeness of the accounting records, and timely preparation of reliable financial information.

The Institute of Chartered Accountants of India (ICAI) had issued a Guidance Note in November 2014. This guidance note was revised subsequently and the ICAI issued a revised ‘Guidance Note on Audit of Internal Financial Controls Over Financial Reporting’ (Guidance Note) on 14 September 2015.

Our First Notes provides an overview of the Guidance Note issued by ICAI.

KPMG in India is pleased to present Voices on Reporting – a monthly series of knowledge sharing calls to discuss current and emerging issues relating to

financial reporting

On 14 October 2015, we covered following topics:

i. Ind AS 32, Financial Instruments: Presentation

II. Exposure drafts on Ind AS 11, Construction Contracts and Ind AS 18, Revenue.

Financial instruments

Ind AS 32, Financial Instruments: Presentation establishes principles for presenting a financial instrument as a liability or equity. In the call we provided an overview of the basic concepts around classification of financial instruments into financial assets, financial liabilities and equity instruments.

Exposure drafts of Ind AS 11 and 18

The ICAI has recently issued following Exposure Drafts (EDs):

i. Ind AS 11, Constructions Contracts along with the appendices corresponding to IFRIC 12, Service Concession Arrangements and SIC- 29, Service Concession Arrangements: Disclosures

II. Ind AS 18, Revenue, along with the appendices corresponding to IFRIC 13, Customer Loyalty Programmes, IFRIC 18, Transfers of Assets from Customers, SIC 31, Revenue - Barter Transactions Involving Advertising Services and

III. Consequential amendments to other Ind AS.

In the call, we provided key highlights of the above mentioned EDs issued by ICAI.

Missed an issue of Accounting and Auditing Update or First Notes?

IFRS NotesRBI recommends a road map for implementation of Ind AS for banks and NBFCs

30 September 2015

Recently on 16 February 2015, the Ministry of Corporate Affairs (MCA) issued the Companies (Indian Accounting Standards) Rules, 2015 which lays down a road map for companies other than insurance, banking companies and Non-Banking Financial Companies (NBFCs) for implementation of Ind AS

(converged with International Financial Reporting Standards (IFRS)) in a phased manner starting from 1 April 2016. Currently, Ind AS for corporates is under implementation.

On 29 September 2015, the Reserve Bank of India (RBI) through its Fourth Bi-monthly Monetary Policy Statement, 2015-16 informed the stakeholders that it has recommended to the MCA a road map for the implementation of Ind AS for banks and NBFCs from 2018-19 onwards.

The RBI has constituted a working group (Chairman: Shri Sudarshan Sen) for its implementation. The report of this working group will be uploaded on RBI’s website by the end of October 2015 for public comments. A detailed road map would be issued later.

The information contained herein is of a general nature and is not intended to address the circumstances of any particular individual or entity. Although we endeavour to provide accurate and timely information, there can be no guarantee that such information is accurate as of the date it is received or that it will continue to be accurate in the future. No one should act on such information without appropriate professional advice after a thorough examination of the particular situation.


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