How management affects financial reporting-the case of Tata Power and Adani Power

As a veteran reader of annual reports would know, accounts (even audited ones) are subject to several adjustments/interpretations. This is because on the same facts, different people can take the same view. Auditors merely ensure that the management interpretation does not cross canons of incorrectness.

Facts in brief
Adani and Tata had bidded for coal based power plants respectively with capacities tied up under power purchase agreements (“PPAs”) for twenty five years with substantially fixed tariffs. The PPAs for these plants were made based on the commitments / understanding that domestic coal linkages would be available to meet the fuel requirements. However, adequate coal linkages were not made available due to various reasons not attributable to the respective subsidiary companies. In response to pleas for compensating the losses due to above, the respective state electricity regulators had granted part relief in form of interim compensatory tariffs, however this matter was litigated and has not reached finality as of now.

Stance taken by Adani Power-Recognize revenue
As per the assessment by the Management, it would not be unreasonable to expect ultimate collection of an equivalent amount as the CT towards relief due to impact of Force Majeure events which is predicated on the legal advice that the CERC may be guided by the principles of restitution / mitigation of the impact of the promulgation of the Indonesian Regulations and non-availability of short supply in determining the extent of impact of Force Majeure events. In view of the aforesaid, the Company has continued to recognise total revenue of H3,374.66 Crores on account of the CT upto 31st March, 2016 (including H674.19 Crores for the year ended 31st March, 2016 and H857.35 Crores for the year ended 31st March, 2015) based on the formula and methodology prescribed by CERC vide its order dated 21st February, 2014 considering the same as the most appropriate basis for measuring impact of the Force Majeure

Stance Taken by Tata Power-No revenue recognition-Director's report for FY 2015
CGPL has been legally advised that it has a good arguable case. However, in view of the pending appeal as mentioned above and considering that the amounts associated are significant, CGPL has not recognised revenue amounting to ` 757.89 crore for the year ended 31st March, 2015 and ` 1,019.06 crore for the period from 1st April, 2012 to 31st March, 2014. 
Above stance not expected to change as the company has not recorded this income in the audited accounts for the year ended 31 Mar 2016.


Takeaway
Both the below companies are audited by the same Big 4 auditor Deloitte. Yet on very similar facts and the identical rulings, the companies took a very different view to revenue recognition, and the . Tata Power conservatively chose not to record revenue considering the high stakes involved, while Adani Power decided to record it basis management assessment. Accounting risk is therefore higher in the latter, from an investor perspective. While the statutory auditor has qualified the audit report in Adani possibly for this reason citing it as an internal control weakness, this is more a process rebuke than calling it wrong accounting
According to the information and explanations given to us and based on our audit, a material weakness has been identified as at 31st March, 2016 in the Company relating to inadequate internal financial controls over financial reporting in respect of revenue recognition on account of additional tariff claims pending determination by regulator, and final outcome of the litigations.

Financial Management & Power Sector Series_Bidding assumptions

Generally in a tender involving multiple year supplies, assumptions about inflation, operating efficiency changes etc are vital. In nearly all tenders, the bidder runs the risk of wrong estimation but in the power sector there is too much at stake.

If a bidder(for power project) cannot complete a project due to under-costing, everyone loses. Also, there are many technical details at play. The regulator who scrutinizes all the firms may be in a better position than the bidding firms,  to estimate the various variables for bidding. That is why the CERC itself notifies the various rates to be used for bidding evaluation and payment. In the interest of transparency, the detailed methodology of calculating these rates is also mentioned so that people who differ, can use their own internal rates. For anyone with an interest in macroeconomics/financial management, the methodology document is a goldmine.

Wonder how is your electricity tariff calculated? Read on

This post explains how the generating companies calculate(and get approved from Electricity Regulatory Commissions) the tariff for their power. It does not cover UMPP/long term PPP based tariffs. The basis for this post is the National Tariff Policy.

Infrastructure economics have certain unique issues. They have high fixed costs(both initial and operating) relative to variable costs. Debt financing being in vogue to extent of 70%+ project cost, interest and(in case of foreign debt-forex MTM fluctuations) becomes a major chunk of recurring costs. Given that the facility once set up is a monopolist(atleast in a few areas), smart pricing is the key to profit maximization. However, as any micro economics textbook would tell you, producers may be tempted to lower the output(not in public interest) to maximize their profits.

The power sector can be broadly divided into

1. Generation. Here, regulators design incentives to encourage producers to operate the plant efficiently and to the fullest possible capacity. Competition via free markets is the eventual goal.
2. Transmission & Distribution :-This was, is, and is likely to remain a natural monopoly where prices have to be regulated.

The objectives mentioned in the tariff policy(with my comments in bold italics) are to

(a) Ensure availability of electricity to consumers at reasonable and competitive rates(no monopoly abuse)
(b) Ensure financial viability of the sector and attract investments(Since Govt cannot fund(or properly execute) the necessary power projects)
(c) Promote transparency, consistency and predictability in regulatory approaches across jurisdictions and minimize perceptions of regulatory risks(change of coalition Govt in the states etc)
(d) Promote competition(to eventually determine basis for PPP/free market rates), efficiency in operations(allow pass through only for controllable costs) and improvement in quality of supply(increase the expected Plant Load Factor(PLF) yearly).

For a five year period(say 2009-14), the utility gets its capex plans and projections approved at a public hearing where consumer and industry associations can voice objections(which they usually do). Then each year, the utility estimates the operating parameters in advance and projects its operating costs accordingly. Depending on forecasted output and consumer classes, the tariff is proposed. The aforementioned associations try to bring down the costs while the utilities inflate it. If you want to really understand the economics of this industry, try reading any of the tariff petition proceedings on the CERC site. They are quite illuminating(the behind the scenes fight for every rupee!!). Typically, the regulator fixes a mid-way value for most items.  If the utility achieves/surpasses its operating benchmarks, it can charge an incentive tariff from the customer.

It is on the basis of this forecasted cost that your bill is prepared. At the year end, the surplus/deficit is calculated and then passed on. Since there cannot be any direct bill refund(so far infeasible), consumers as a class get that bill adjustment.

Financial Management & Power Sector Series_Hedging

The policy states that "Foreign exchange variation risk shall not be a pass through. Appropriate costs of hedging and swapping to take care of foreign exchange variations should be allowed for debt obtained in foreign currencies"

This seems fair. The producer is paid to hedge his risks to take care of forex variations. Imperfect hedging will be at his expense/profit. Given this, power companies are prime candidates for derivatives in this regard. 

Financial Management & Power Sector Series_ROE v/s ROCE

Debates still range on which is the better metric to use for performance evaluation-ROE or ROCE. Those proposing ROE take the narrow shareholder perspective but those wanting ROCE maintain that ROE may lead to too much 'leveraging' and risk taking. Notionally, the policy does permit  the CERC to adopt either approach but The National Tariff Policy and the various State policies I have seen so far seem to favour ROE as the basis for tariff determination. The D/E ratio is optimal at 70:30 for the project so focus does seem ROE.

The reason may be that the intent is to ensure that resources flow into the power sector. So the risk capital rate should be ROE. Also, interest costs are allowed as 'pass through' so the producer can earn only on his equity infusion considering that consumers pay his debt service costs.

Financial Management & Power Sector Series_Debt Equity Ratio

Debt/Equity Ratio is that famous unresolved issue in financial management. There is no certain solution in sight. Firms assess their cash flows, risk, tax structure and capital raising options before deciding their optimal debt equity ratio. But the GOI has devised a solution at last.

As per the National Tariff Policy, a Debt/Equity Ratio of 70:30 is the norm. While promoters can infuse equity in excess of 30%, that excess equity will earn a return at the weighted average debt interest rate(and NOT at the higher ROE). Needless to say, equity less than 30% will not get any 'credit' for the deficit but will earn its actual ROE.

Given the terms, it would be foolish to infuse excess equity when you are compensated at the rate of debt only. That seems the intent of GOI to ensure that project cost of capital does not cross a certain ceiling