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Indian Utilities: Tepid, Bumpy & A Lot Less Crowded -
Reducing RPWR Target to INR100; Maintain Underperform
Highlights
The slowdown in Indian power consumption growth and declining merchant prices over the last year has
two broad implications for utilities: raising money to build new power stations will be more difficult and
political pressure to fix the "broken" distribution sector will increase. The first factor will play out
immediately; the second, over time. This places a premium on incumbency and a low cost structure. Among
the stocks we cover, the beneficiary should be NTPC. Implications for Reliance Power are less attractive.
India continues to suffer from a shortage of electricity. The low level of power consumption growth
and declining merchant prices reflect problems with the distribution sector more than a deceleration in
underlying demand growth. In any case, power consumption was up 4.3% in 2010; installed capacity was
up 8.0%; and merchant pricing is trending down. The good old days for the IPPs may now be over.
NTPC is the lowest cost provider of electricity in India. It is also the largest operator in India and has
almost all of its capacity locked up in long-term power purchase agreements with a regulated return on
equity of 15.5%. If power consumption growth in India is slowing (for whatever reason), NTPC stands to
benefit as (i) reduced investment in the sector will reduce competition for fuel and dispatch; (ii) the
company's regulated business is largely insensitive to merchant pricing.
We are maintaining our target price on NTPC at INR190. NTPC is currently trading at the lower end of
its long term average on a P/E or P/B basis. If the company is able to adjust its tax expense this quarter
so as to escape MAT liability, earnings growth for FY2011 should be INR11.24, up 6.1% Y/Y.
Reliance Power is stuck between a rock and a hard place. The company is rapidly developing its
projects yet – in our view - does not have the cash to execute its expansion plan into 2012 without
additional equity. Any sign that Reliance Power is slowing its development of new projects will be
interpreted as either a lack of confidence in the domestic power market or internal concern about the
company's finances (both clear negatives). In our view, the company is likely to raise more cash before
the end of 2011 – and, in some ways, the sooner the better given the deteriorating negotiation position
that a declining cash balance creates. However, the first half of 2011 looks like an unattractive time for
Indian companies generally and Reliance Power in particular to seek new equity.
We are lowering our target price for Reliance Power to INR100. The lowered valuation reflects the
deteriorating pricing environment and the limited range of options: Reliance Power cannot suspend
construction to preserve cash without a negative response from investors. Conversely, given the long-lead
times, the company cannot accelerate construction to bring earnings forward
Investment Conclusion
We rate NTPC Market-perform (NATP.IN, Target Price INR190). Given NTPC's regulated rate of return
business and the company's reluctance to enter a competitive bidding process for its generation capacity, we
believe that the upside to current valuation is limited.
We are lowering our target price for Reliance Power to INR100. We are maintaining our Underperform
rating. The lowered valuation reflects the deteriorating pricing environment and the limited options range of
options for the company: it cannot suspend construction to preserve cash or acceleration construction to
meaningfully bring earnings forward.
Reliance Power recently affirmed progress on over 20GW of coal-fired capacity and coal investment in
Indonesia. All this expansion requires cash. Reliance Power raised INR135.5 billion in its IPO in January
2008. Reliance Power has stated that – through project financing – it can lever its power stations 75%:25%
debt-to-equity. This effectively quadruples the amount of cash Reliance Power has had to spend on building
power stations to INR542 billion. To date, the company has spent INR122 billion and therefore has – at the
beginning of 2011 – an additional INR420 billion remaining to spend.
It is just now at the peak of its capital spending cycle. If Reliance Power is able to lever its balance sheet up
three times, this would suggest that funding may last until the approximately March 2012
In our view, the company is likely to raise more cash before the end of 2011 – and, in some ways, the
sooner the better given the deteriorating negotiation position that a declining cash balance creates. However,
the first half of 2011 is an unattractive time for Indian companies generally and Reliance Power in
particular to seek new equity.
And that is where the trouble starts. A deferral of negotiations with new equity investors in order to wait
for the stock to rebound increases the likelihood that the stark math painted above – where Reliance Power
is out of cash and out of sources of debt funding by beginning of 2012 – is the opening topic of
conversation.
Details
India has a chronic lack of electricity supply. Roughly 400 million people do not have access to electricity.
Indian power consumption per capita is ~1/3rd that of China. Yet the single best reason not to invest in the
Indian power sector is a simple one: everybody already knows this.
As has been widely reported, the Sensex had been the second-worst performing index in the world in 2011,
behind only Egypt (Exhibit 2). Concerns about inflation and the sustainability of economic growth in India
are driving the poor performance. Reliance Power is down 23.3% since January 1 and has underperformed
the Sensex by 1,240bps. NTPC is down 8.3% since January 1 although it has outperformed by 260bps
Since the beginning of 2010, NTPC, Reliance Power and Tata Power (BBG: TPWR; Not Covered) have all
underperformed the Sensex (Exhibit 4). The Sensex is up 4% since the beginning of January 2010.
There is (at the end of January 2011) 170GW of installed capacity in India. As we discuss in this report,
India's reputation as a difficult place to build and operate infrastructure is well earned. New capacity growth
at 8% in 2010 continues to lag announced plans and capacity expansion since the end of 1999 has grown at
a 5.5% CAGR
Even given clear demand, significant plans for capacity growth and the regulatory environment revised by
the Electricity Act 2003 to encourage expansion of the generation sector, this total capacity of newly
commissioned power stations over the last decade has been disappointing. The greatest annual increase in
installed capacity in India over the last decade came in 2007 when 13.4GW of new capacity was installed
Coal-fired generation dominates the power fleet, creating further problems in terms of coal
supply
Recently reported results have highlighted that distributing electricity to those who require it is - if anything
- more complicated than generating power. The Central Electricity Authority calculates and publishes
available and required electricity on a monthly basis (Exhibit 8). That deficit has been decreasing on a
year-on-year basis in recent months.
This slowdown in Indian power consumption growth over the last year relates to the state of finances at
State Electricity Boards more than an underlying drop in demand for electricity. The distribution sector
throughout most of India suffers from high levels of losses, or theft, of electricity. In some instances,
provision of electricity is, for a distribution company, a loss-making exercise as the cost of the units stolen
exceeds the profit from the electricity sold. In that circumstance, distribution companies (operated by the
State Electricity Boards that purchase electricity by the utilities) will – absent instruction to maintain supply
– simply shut down electricity supply at certain times of the day in order to limit losses.
There are two broad implications for the utilities sector if the poor state of the balance sheets of the
distribution companies rather than the underlying demand for electricity is the determining factors of power
consumption growth: raising money to build new power stations will be more difficult and political
pressure to resolve the "broken" distribution sector will increase.
The first factor will play out immediately; the second, over time. This place a premium on incumbency and
low cost. The long-term beneficiary in our view should be NTPC. In fact, for NTPC this is less of a
problem than for the rest of the industry. NTPC's fleet is largely regulated and gets paid a return on equity
for availability. For the rest of the industry, payment is – largely - based on electricity supply. Certainly for
the power stations that are being built currently by IPPs, the base case scenario has involved the ability to
sign long-term power purchase agreements at Rs3.50/KWh or more and to sell power into the merchant
market at Rs5-6/KWh or more. The merchant market has been trending down since 2008
The average price of merchant electricity since the middle of 2008 as reported by IEX India has been just
over Rs5/KWh. But the trend has been down the whole time. There is some seasonality involved: prices
tend to peak in the May-June time period and trough in January-February. We are currently therefore
emerging from a trough and the fact that the average three month price has been lower than the long-term
average since for the last six months is – in part – a function of seasonality.
But there is something else going on too. The peak in May-June 2010 was lower than the peak in 2009 and
the current trough is lower than the troughs in either 2010 or 2009. In short, merchant power prices are
falling.
Notwithstanding the low level of power consumption growth in India currently (4.3% in 2010) and the soft
merchant market, given that Indian GDP growth remains in the high single digits, it is unlikely that power
consumption growth can remain half of that level. The "classic" relationship between power consumption
growth and GDP growth suggests that developing economies use a lot of electricity for each additional unit
of GDP. The "power multiplier" doesn't generally fall below one until the economy is heavily
industrialized and is transitioning to services, transport and higher value-added manufacturing for its
sources of economic growth (i.e., the United States in the 1970s; China today). To suggest that India can
continue to growth at 9-10% with power consumption growth of 4-5% seems unlikely based on the state of
the Indian economy and this longstanding relationship between power consumption growth and GDP
growth.
And yet, that is what we have documented previously. Notwithstanding the fact that India would not be
viewed by many as a post-industrial economy, its power multiplier has been below 1.0 since 2003 (viewed
on a rolling five year basis).
Looking at the difference between real GDP and electricity consumption cumulative average growth rates
over the period from 1976 to 2009 highlights this inflection point (Exhibit 11). In no period before 2003
was real GDP growth (measured on a 5-year CAGR) greater than electricity production growth (measured
on a 5-year CAGR). In no period since 2003 has the inverse been the case. And if we look solely at data
since 2003, a new relationship between electricity production and real GDP growth appears to be emerging.
India's power multiplier has been ~0.7 for the past five years (Exhibit 12). Annual data has not yet been
released but the quarterly data suggests that the power multiplier for the five years ended December 2010
will be lower still.
There are (at least) three explanations for what is happening in India.
First, the low "power multiplier" is an aberration and if power delivery growth cannot increase, economic
growth rates will fall.
Second, India's economic development is not post-industrial but ex-industrial. That is, the heavy industry
growth phase that has been part of economic development everywhere since the Industrial Revolution will
simply get skipped in India for a lack of power – in the same way the country has "skipped" building copper
wires to every home in order to provide landline telephone service and instead jumped straight to ubiquitous
mobile phone usage. As a result, a power multiplier of 0.7 for a developing country is sustainable.
However, the definition of "developing" has to change.
Third – and most likely -power consumption growth will accelerate and the power multiplier in India will
increase over the next decade because of an increase in installed capacity and improved access to fuel
supply. Both of these things will, in our view, result in cheaper electricity that "funds" more powerintensive
activities.
Of course, all three outcomes are bad for the Indian power sector and – in particular – IPPs like Reliance
Power that are not CERC regulated.
Reliance Power: Arriving Late to the Party?
Reliance Power's net profit for the quarter ended December 31, 2010 (3QFY11) was INR 1,436M, 2.2%
below consensus estimates of INR 1,469M. Operations remain middling. Since the commencement of
Rosa's second unit in June 30, 2010, Rosa's generation has increased sequentially from 545.7 GWh
(2QFY11) to 713.9GWh (3QFY11). However, Rosa's utilization rate for 3QFY11 was 53.9%, below the
national thermal utilization of 69.7% and Private Sector IPP thermal utilization of 64.4%.
But for Reliance Power, operating result is now a tertiary consideration. The key questions are (i)
commissioning dates for projects under construction and (ii) the rate of cash consumption.
In terms of the commissioning timeline, Reliance Power confirmed this week that the company is planning
to commission the Samalkot gas-fired power stations by the end of the year and that the Sasan and Tilaiya
coal mines are on-track. The company also affirmed progress on over 20GW of coal-fired capacity and coal
investment in Indonesia.
All this expansion requires cash. Reliance Power raised INR135.5 billion in its IPO in January 2008.
Reliance Power has stated that – through project financing – it can lever its power stations 75%/25% debtto-
equity. This effectively quadruples the amount of cash Reliance Power has had to spend on building
power stations to INR542 billion. To date, the company has spent INR122 billion and therefore has – at the
beginning of 2011 – an additional INR420 billion remaining to spend, including INR2B of accumulated
EBITDA contribution. Reliance Power is just now at the start of peak capital spending.
By the end of FY2011, commissioning for the first units of Rosa Phase II, Butibori and the Samalkot will
have started, which will increase total installed capacity to ~5,400MW by December 2012.
The rough math is simple: ~30GW of thermal power stations requires ~USD30B in India. The total funding
capability based on the IPO raise and the 75%/25% debt-to-equity target is INR542 billion (USD12 billion).
Cash flow from operations from the early projects will fund construction of the later projects. Timing
matters. And the company has discussed a need for more equity at some point. The question is: when?
The company obtained approval from shareholders to raise additional equity in September 2010. We
believe this equity raise may occur before the end of 2011. The recent drop in Reliance Power's share price
makes this an extremely unattractive time to raise new equity. Accordingly, cash burn is all important.
Reliance Power is stuck between a rock and a hard place: any sign that it is slowing its development of new
projects (Exhibit 13) will be interpreted as either a lack of confidence in the domestic power market or
concern about the company's financial position (both are obviously negative). At the same time, the first
half of 2011 is shaping up for a variety of reasons to be an unattractive time for Reliance Power to raise
more cash. Shares in Reliance Communications and Reliance Infrastructure have both dropped ~30% and
~25% respectively since January 1 on various negative media reports including – as recently as February 16
– Anil Ambani's being investigated by the Indian Central Bureau of Investigation over the allocation of the
2G spectrum. Reliance Power's share price has also come under pressure.
Based on company guidance, we use a rough estimate of USD1B in capital costs for 1GW of installed
capacity. We assume some savings for the expansion of the Sasan, Krishnapatnam and Tilaiya Ultra-Mega
Power Plants (USD800M/GW). We also assume a straight line capital spending pattern for two years prior
to the commissioning of the power station. The implied capital spending cycle is therefore rough. Without
the aid of a recent balance sheet or cash flow statement from the company, it is not possible to confirm the
precise timing of spending estimates. However, by our calculations, Reliance Power is approaching the
peak of its capital spending cycle currently
Levering book equity three times suggests available funding at December 31, 2010 may have been
INR420B, assuming total capital spending (all-time) to the end of 2010 was INR122B
If Reliance Power is able to lever its balance sheet up three times, this would suggest that funding may last
until the approximately March 2012 (Exhibit 18). At that point, access to funding would be exhausted but
only Butibori, Rosa, Samalkot, Goa and Kochi would be commissioned (~3.3GW of capacity
However, there is – in our view – a problem with the assumption that Reliance Power can lever up its entire
balance sheet to three times the level of book value of equity. First, Reliance Communications' stock
(BOM:532712, Not Covered; another part of the Reliance ADAG group) is down ~30% YTD because of –
among other things – its increasing debt load (Exhibit 21). We believe that – given the lackluster growth in
power consumption and softening merchant prices - Reliance Power may struggle to raise additional debt to
bring its debt/equity ratio up to this level. And if it does – through the project financing arrangements
already in place - we believe that the stock price may well come under further pressure from investors. The
level of leverage required to get Reliance Power through to the first half of 2012 before additional cash is
needed would place Reliance Power among the most heavily geared publicly companies in India (
In short, the assumption that Reliance Power can get to the start of 2012 before it requires more cash is
based on the fact it can lever up all of the cash it has raised three times. If – by virtue of debt covenants or
for any other reason – Reliance Power cannot lever in the manner that it has guided, the cash will run out
sooner.
The Danger of Just-in-Time Financing
Burn rate is an important consideration for Reliance Power given that we believe the company will need to
raise additional equity in order to continue its capital program into 2012.
On August 12, Reliance Power filed a notice with the National Stock Exchange announcing it was seeking
shareholder approval to – among other things - raise more funds by issuing equity shares to Qualified
Institutional Buyers and through issuing securities in international markets. The resolution allows Reliance
Power to raise equity from Qualified Institutional Buyers by an amount that does not result in an increase in
shares then outstanding of more than 15%. The international issuance provision has a similar clause of up to
10%. Pricing of the new equity is in both instances in the absolute discretion of the board. The resolution
was approved by shareholders through postal ballot and announced in September 2010.
The mechanism to raise more equity is therefore entirely in the hands of Reliance Power's board. But given
that the very mention of available funding is likely to set a very low floor on pre-money valuations, it is
generally in the interests of a company in Reliance Power's position to initiate discussions with new
investors as soon as possible. Of course, given what has happened to the stock in the last few weeks, it is in
Reliance Power's interests to delay these discussions for as long as possible.
And that is where the trouble starts. A deferral of negotiations with new equity investors in order to wait
for the stock to rebound increases the likelihood that the stark math painted above – where Reliance Power
is out of cash and out of sources of debt funding by beginning of 2012 – is the opening topic of
conversation.
In that instance, the discounted value of the company's future cash flows is of significantly less interest than
the break-up value of the company's existing assets. And that discussion is unlikely to go well for Reliance
Power. Specifically, it is a relatively simple matter to value the operating power stations at Rosa, Samalkot,
Goa and Kochi (based on NTPC's enterprise value, roughly USD1.2B per GW). But the fact that the
conversation is occurring at all means that cash balances and investments are likely to have dwindled. That
leaves the partially built power station fleet – Sasan, Butibori, Krishnapatnam, Tilaiya and Chitrangi - and
the expansions at Rosa and Samalkot.
Depending on whether you are the buyer or the seller, determining the value for a partially completed
power station in a market with 126GW of capacity currently under construction and an additional 408GW
in planning is either very difficult or extremely simple. For the buyer, the value is approximately zero
given that – with installed capacity growth in 2010 roughly 2x power consumption growth, it is a buyer's
market. For the seller, the perspective will obviously be different. However, the answer is unlikely to be
greater than 1x the cost of construction to date.
It is in Reliance Power's interests to avoid discussions where the break-up value of the company is one of
the parameters for assigning a valuation. And that means raising equity sooner rather than later. Our revised
valuation for Reliance Power is based on a discounted cash flow analysis assuming a 25% increase in the
shares currently outstanding. The valuation is INR100
NTPC: Damn the Taxation, Full Steam Ahead
NTPC is the lowest cost provider of electricity in India. It is also the largest and the best operator in India
and has almost all of its capacity locked up in long-term power purchase agreements.
Yet, in the third quarter of 2010, NTPC reported that several of its power stations were backed down
because of the refusal of various State Electricity Boards to pay for the electricity that would have been
generated. In the first nine months of the financial year (April-December 2010), NTPC estimates that it
could have generated an incremental 10,000 GWh or roughly 6% of gross generation over the period.
NTPC offers the cheapest electricity supply in India. By virtue of the regulations under which NTPC
operates and the long-term power purchase agreements that it signs with the State Electricity Boards
("SEBs"), the SEBs are liable for all of NTPC's fixed costs and a return on equity of ~15.5% as long as
NTPC is available for dispatch more than 85% of the time.
There are two implications here. First, as long as NTPC is available for dispatch, its earnings are largely
unaffected by the decision of a particular SEB not to purchase electricity. There are additional benefits to
NTPC from operating at high utilization because of the way the CERC regulations are drafted. Because it
is able to generate electricity at a heat rate that is lower than the nominal heat rate in the electricity
regulations, NTPC effectively gets paid for coal that it does not burn. However, if NTPC doesn't generate
the electricity, it cannot capture this benefit. And backing down and re-firing coal-fired power plants is
inefficient. In short, the actions of the SEBs matter in terms of quarterly earnings – but only at the margin.
Second (and more broadly), if State Electricity Boards cannot afford to pay the variable cost component of
NTPC's electricity generated from domestic coal (by our estimate, less than Rs1.50/KWh), long-term
prospects for IPPs building power stations that will import coal based on business cases that assume a
payment of Rs3.50KWh (at a minimum) are bleak
And the poor operating performance of NTPC's power stations is clear from a review of the rolling gross
generation growth over the last twelve months. Rolling annual gross generation growth is currently 1.4%
for NTPC (Exhibit 23). To put that in context, annual energy demand growth in India has been 5-7% in
recent years and installed capacity growth was 8% in 2010 and is trending higher in 2011. Low power
consumption growth rates in India are often attributed to a lack of capacity growth or a lack of coal. In this
instance, capacity is not the problem. For NTPC, utilization has fallen in two of the last three quarters and
was flat in the second quarter
Coal provision from imports and Coal India has increased modestly over the last year. Total coal increased
from 98.58 million tons in the nine months to December 2009 to 100.44 million tons in the nine months to
December 2010 – a 1.8% increase.
The bad news in relation to NTPC is now all out: the company is currently flirting with the Minimum
Alternate Tax regime which would serve to lower earnings by limiting the amount of notional tax expense
the company can recover from State Electricity Boards pursuant to its Indian electricity pricing regulation.
Commissioned power stations in the 2011 financial year will disappoint once again. Finally, demand for
NTPC's electricity – the cheapest in India – fell in the most recent quarter.
But the bad news is temporary and understood. The good news has longer term implications. The company
has set the goal of signing up as much capacity under long-term power purchase agreements regulated by
the CERC pricing mechanism (which prescribed a 15.5% return on regulated equity) as it could. In the
third quarter, the company announced it had signed up 100GW under this pricing mechanism which would
take NTPC until 2020 to build out (
It has been difficult to understand the rationale for signing up new capacity under the CERC regulations
when NTPC is the lowest cost producer in a tightly supplied market with competitive bidding available.
However, if – as is now the case – power consumption growth is lower than installed capacity growth, the
near-guarantee of a 15.5% return on regulated equity is increasingly attractive.
Of course, having signed up the long-term power purchase agreements is one thing; building the power
stations is another. And NTPC's track record has been poor. The company's guidance of 4,150MW of new
installed capacity in the financial year ended March 31, 2011 has been lowered to 3,150MW. The
compounding annual growth rate of new installed capacity between March 2005 and March 2010 was
4.2%. On that front, the current financial year may be an inflection point as 3,150MW is an 11% increase
from the end of March 2010. However, to reach a target of 100GW by March 2020, NTPC will need to
expand installed capacity at a 13.5% CAGR for a decade
Assuming that NTPC maintains availability well above 85% (and therefore can over-recover its fixed
costs), uses 70% debt to finance its expansion, maintains a steady level of income from investment sources,
and operates at a high plant load factor so that it can over-recover fuel costs, earnings over the next decade
could also expand at a rate in excess of 10% without undue reliance on other income, unscheduled
interchange or over-recoveries (Exhibit 26 and Exhibit 27).
NTPC Valuation
Given that the company's return on equity per power station is prescribed, the dividend pay-out ratio has
been steady for the last five years and the industry is heading towards a state of overcapacity in our view,
we use a two-stage dividend discount model for valuation. NTPC's dividend pay-out range is clear from the
last five years and can be expected to hold steady while India's power generators go through a period of
rapid capacity expansion. At the end of that expansion period, India's power sector – including NTPC –
should be able to grow no faster than the broader economy or nominal GDP. That transition is, in our view
likely to occur at the end of this decade.
We assume that NTPC maintains the current low dividend payout levels up through a terminal year, after
which time the company dividends out the majority of earnings as expansion opportunities dry up (Exhibit
28).
To implement this dividend discount model, Stage 1 dividends (FY2012-2020) are valued using the formula
for present value of a growing annuity: PV = D/(i-g)[1 – ((1+g)/(1+i))n]. The payment in the initial period is
our estimate for the dividend in 2012, the discount rate is the cost of equity, time period runs from 2012 to
2020 and the growth rate is calculated as Growth rate = (1 – Pay-Out ratio) x Return on Equity. In Stage 2,
the terminal value of the dividends equals the present value of a growing perpetuity PV = D/(COE – g)
starting from the end of 2020 where the initial period payment is the dividend in 2021.
Earnings cannot grow faster than the rate at which the company re-invests (1-Pay-out ratio) multiplied by
the return on equity. When the dividend pay-out ratio are stable over time and return on equity is stable and
known, the observation ceases to be theoretical and takes on practical application. In short, with an
approximately 35% dividend pay-out ratio and a 16% return on equity, growth will be approximately 10.4%.
Extending that insight into Stage 2, a given perpetual growth rate implies a corresponding pay-out ratio
since NTPC's returns on equity will remain fixed.
We employ a return on equity of 16% through both stages of the model, extend the dividend pay-out ratio
for 2009 through Stage 1 (implying a growth rate of 10.4%) and assume a perpetual growth rate of 3%
starting from 2021 (implying a dividend pay-out ratio of 81.25%). Furthermore, we apply the calculation of
NTPC's cost of equity, where risk-free rate is the yield on Reserve Bank of India Reverse Repo rate, beta is
the two-year raw beta as compiled by Bloomberg and the risk premium is calculated based on the difference
between the implied cost of equity of the Bombay Stock Exchange Index (Sensex) and the risk-free rate.
We use a cost of equity of 11.75% derived from the Reserve Bank of India Reverse Repo yield of 5.25%, a
market premium of 10.09% and a beta of 0.644.
Rather than using the long term Indian government bond yield as our risk free rate, we use the Reserve
Bank of India Repo yield because Indian bond yields have traditionally been high due to inflation
expectations. The CPI in India is currently growing at approximately ~12% annually. Since we do not
account for inflation in our growth projections, we use a short-term risk free rate that does not incorporate
inflation expectations.
We use historical beta (two-year raw beta) as compiled by Bloomberg. To the extent that a company enters
a new business; fundamentally changes its supply chain or customer base; or is subject to a dramatic change
in market structure, it is certainly possible to argue that a non-historical beta is warranted. None of those
things have happened.
Finally, we are using a country equity risk premium for India of 10.09%. This figure was derived
subtracting the risk-free rate described above from the implied cost of equity of 14.0% that the market
attributes to the Bombay Stock Exchange Index. This market cost of equity was calculated using the
modified Gordon Growth formula P/E = (1-g/ROE)/(Ke-g), where P/E is calculated as the price per share of
the index over its forward EPS, g is India's average annual nominal GDP growth and ROE is forward EPS
over historical BVPS. Adjusting market risk equity premium, the upside to valuation remains limited.
Given that NTPC is free cash flow positive, we also prepare a discounted cash flow valuation using the
same cost of equity components as the dividend discount model above
Understanding the Indian Regulatory Environment
The discussion below provides background on the Indian regulatory environment for power generation. In
general, an electricity generation asset in India may fall into one of four regulatory schemes:
Central Electricity Regulatory Commission ("CERC") regulation, issued pursuant to Sections 62 and
79 of the Electricity Act of 1993 ("the Act");
State Electricity Board regulation, issued pursuant to Section 62 and 82 of the Electricity Act;
Ultra Mega Power Plant regulation issued pursuant to Section 63 of the Act; or
Independent Power Plant status, pursuant to Section 63 of the Act;
In addition, all power stations can sell electricity into the Unscheduled Interchange system.
The generation, transmission and distribution of electricity in India is largely regulated by the Electricity
Act 2003. The Act aims to develop the industry, promote competition, protect supply of electricity to all
areas and promote environmentally benign policies. For current purposes, the key aspects of the electricity
reforms introduced in 2003 are: competitive generation (any company can establish, operate and maintain a
generating station without a license, as long as the station complies with prescribed technical standards
relating to grid connectivity – and obtaining land, water use and other permits as required by separate
legislation); captive generation; and open access.
Further, the Act contemplates two means by which centrally-regulated power generation companies may be
paid for electricity produced – either through tariffs prescribed under section 62 of the Act (and set out in
the CERC regulations issued in January 2009 ("the 2009 regulations"), or via a competitive bidding
process. This competitive bidding process falls into two categories: either Case I where power stations bid
to supply electricity or Case II, where power generation companies bid to build and operate power stations
with a prescribed PPA attached from the outset. Ultra Mega Power Projects are an example of the Case II
process.
The CERC regulations and the State Electricity Board regulations provide heavily detailed prescriptions for
how operating costs, fuel costs and return on equity are to be calculated and recovered. In short, the utility
is able to pass through taxes, interest expense, fuel costs and operating expenses to the purchaser and
achieve a return on regulated equity as long as the utility meets set performance criteria.
Ultra Mega Power Projects are large-scale projects where the central government has coordinated land,
water usage, transmission, environment approvals and fuel source requirements and offers the projects on a
competitive basis to developers to build and operate through long term contracts. Developers then bid for
the right to develop and operate the projects based on a levelized cost of energy over the course of the
plant's life. The return on equity is determined by the developer and is capped only by (i) the developer's
ability to commission the power station on schedule and within budget; and (ii) the "winner's curse" implicit
in any competitive bidding scenario where the return on equity of the winning bid will tend to be lower than
those of the unsuccessful submissions.
Independent Power Plants enter long-term power purchase agreements with State Electricity Boards, and
sell to the merchant or spot market. These contracts are entered without reference to a prescribed return on
equity.
For the centrally regulated power stations, UMPPs and IPPs, creating value occurs through one of six ways
(i) CERC-regulated Generation Assets
The CERC regulations provide a heavily detailed prescription for how operating costs, fuel costs and return
on equity are to be calculated and recovered. In short, the utility is able to pass through taxes, interest
expense, fuel costs and operating expenses to the purchaser and achieve a return on regulated equity as long
as the utility meets set performance criteria.
The financial performance of generation assets falling under the CERC 2009 regulations tops out at return
on equity in the low 20% range, (assuming 70:30 debt-to-equity), regardless of coal costs and the pricing
environment. However, returns at this level assume that the company can over-recover its costs under the
regulations through fuel efficiency levels and availability above prescribed operating norms. It is important
to note that tightening of the operating norms prescribed through the regulations would result in a
curtailment of returns for regulated assets back to the "black-letter" rate.
Mechanically, the regulations contemplate separate payment of capacity charges covering fixed costs;
energy charges covering fuel costs. Unscheduled Interchange charges are paid through a separate
mechanism outside of the 2009 regulations.
The regulations are intended to ensure that power stations seek to maximize the amount of time during the
year that they are available for dispatch without penalizing the stations for the fact that they may not in fact
be dispatched. Returns on equity are – up to the black letter rate of 15.5% - entirely within the control of
the individual station operator without reference to the broader sector issues of transmission, distribution
and load.
Under the 2009 regulations, an after-tax return on equity of 15.5% is permitted, assuming prescribed
performance criteria are met. An additional 0.5% return on equity is permitted for projects commissioned
after April 1, 2009 and completed on time.
The equity in any project entering commercial operation after April 2009 is deemed in the 2009 regulations
to be 30% of the capital cost. The actual equity above this level is treated as a normative loan (clause 12).
For generating stations entering commercial operation before April 2009, the earlier regulations apply to set
equity and normative loans. The 2004 regulations set a debt-equity ratio of 70:30 for all generating stations
(clause 20; 2004 regulations). Interest on the normative loan is deemed to be (absent specific project
financing) the weighted average interest rate for the entire company.
The three primary drivers of return for the CERC-regulated plants above the black letter rate are set out
below.
Over-recovery of Fixed Costs by exceeding Normative Annual Plant Availability Factor ((a) above)
Utilities with regulated assets subject to the 2009 CERC regulations can over-recover their fixed costs if
plant availability throughout the year is higher than the normative annual plant availability factor set out in
the 2009 regulation. This over-recovery results in an effective return on equity higher than the "black-letter"
rate.
Under the 2009 regulations, power plants recover their fixed costs based on the amount of time during the
relevant period that the power plant is available to generate electricity. These fixed costs are adjusted by a
ratio of actual to normative availability to produce the capacity charge the plant is permitted to recover
through pricing.
This over-recovery mechanism replaces an incentive structure in the 2004 regulation where incentive
payments were made if energy sent out during scheduled generation periods exceeded a prescribed plant
load factor. The change effectively ensures that power plant owners are rewarded for maintaining their fleet
in a state of availability (something that the owner can control) rather than rewarding the owner for dispatch
(which the owner cannot control).
In summary, assets falling within the scope of the 2009 regulations are able to over-recover fixed costs by
exceeding Normative Annual Plant Availability Factors.
Incentive Payments achieved by exceeding Plant Load Factor ((b) above)
While the 2004 regulations are no longer applicable, much of the state regulation that remains in force –
specifically, in Delhi and Maharashtra - still reflects the mechanics set out in the 2004 regulations –
including the incentive payment.
Under the 2004 regulations, power plants were permitted to recover their fixed costs in full and, in some
cases, claim an incentive payment, for exceeding a prescribed target plant load factor. The plant load factor
expresses the amount of electricity that the power station is scheduled to generate as a percentage of total
potential generation at nameplate capacity, adjusted for house consumption. An incentive payment is
available for each scheduled kilowatt/hour sent out above the target plant load factor.
The 2004 regulations linked incentives to coordination of electricity generation with scheduled generation.
This mechanism was designed to alleviate the flaw in previous regulation that encouraged power plants to
operate at times where there was no demand (or load) simply in order to recover fixed costs. That strategy is
rational within a regulatory construct that pays for total electricity sent out but is often detrimental to load
balancing and network stability (discussed in (f) Unscheduled Interchange below). The 2009 regulations go
a step further by decoupling the recovery of fixed costs from energy generation altogether. Instead, plants
are rewarded for being available to generate electricity, regardless of total electricity generated.
In summary, assets falling within the scope of the state electricity generation regulations in, among other
states, Maharashtra and Delhi, are able to obtain incentive payments by exceeding Plant Load Factor.
Over-recovery of fuel cost if plant gross heat rate is below normative gross heat rate ((c) above)
Utilities with regulated assets can over-recover fuel costs if their plants operate at heat rates lower than the
normative heat rates prescribed by regulation. Heat rates are expressed in kilocalories per kilowatt/hour and
reflect the energy input required to generate one kilowatt/hour of electricity (gross). In short, the heat rate
reflects how much coal is needed to run the power station at a given level of output for a given period of
time. Lower heat rates reflect more efficient power stations that use less fuel. Regulated power stations
recover fuel costs based on normative heat rates. Thus, if the actual heat rate is below the normative heat
rate, under the regulations a power station is able to "recover" the cost of coal that it has not burned.
Under the 2009 regulations, fuel costs are recovered as energy charges. However, rather than a strict passthrough
of the cost of fuel purchased or consumed, the energy charge is calculated based upon normative
inputs. Specifically, the energy charge is calculated on a per kilowatt/hour basis based upon and adjusted
for the following:
A prescribed gross heat rate for existing power plants, or the design heat rate for new power plants,
The normative auxiliary consumption of electricity; and
The normative consumption of secondary fuel and limestone.
In short, rather than passing through the actual fuel cost, the regulations allow for a recovery of fuel costs
based on the price of fuel and estimates of fuel consumption given energy produced. An over-recovery of
fuel cost is therefore available to the extent that:
The actual heat rate of the power station is less than the design or prescribed heat rate,
The house consumption of electricity is less than the normative auxiliary rate; and
The actual consumption of secondary fuel and limestone is less than the normative consumption.
Of course, to the extent that the actual levels are greater than normative levels, the utility will under-recover
its fuel cost. Accordingly, the regulation implicitly encourages efficient use of resources and retirement of
inefficient power stations.
In summary, assets falling within the scope of the 2009 regulations are able to over-recover fuel cost if
plant gross heat rate is below the normative gross heat rate.
Similarly, the 2009 regulations set normative operating costs. If a power station operates at costs below the
normative level, this represents a source of value creation for the generator.
(ii) Ultra Mega Power Plants
Section 63 of the Act requires the CERC and the SEBs to disregard the prescription set out in the
regulations issued under section 62 of the Act (e.g., the 2009 regulations described above) and adopt any
tariff if that tariff has been determined through a transparent process of bidding. The Ultra Mega Power
Plant ("UMPP") program operates under this provision.
The UMPP program has superseded the Mega Power Plant program established in the 1990s to encourage
private investment in power plants of 1,000MW capacity or larger. The UMPP program is focused on
projects to develop power facilities of 4,000MW or larger and includes a Ministry of Power-facilitated fasttrack
program for these large scale power projects. The Ministry of Power acquires land, obtains water
rights from the relevant state government, allocates fuel linkages or coal blocks, appoints consultants for
environmental assessments, obtains various other approvals and statutory clearances and secures contracts
for the sale of power in compliance with section 63 of the Act.
The fast-tracking is intended to remove the investment risk surrounding the development of large scale
projects in India and to entice large infrastructure developers and independent power producers to invest.
The competitive bidding process involves various developers submitting a levelized cost of energy
(expressed as an annual tariff over the 25 year period of the UMPP contract). The UMPP is awarded to the
lowest priced, qualified bid. The levelized cost of energy bid is generally lower for the UMPPs than pricing
in long-term contracts with other Independent Power Plants given the scale of the UMPPs, the secured fuel
source and the significant legwork that the Ministry of Power has invested in these projects before they are
awarded to developers.
The opportunity to exceed the "black-letter" return on equity for the UMPPs is clear: the "black-letter"
return does not apply. The UMPPs are not governed by the 2009 (or the 2004) regulations. The developer
is able to set financial metrics to whatever level desired. However, the successful bidder will tend to be the
bidder with the lowest equity returns.
Additional value can be created by the developer/operator to the extent that construction and operating costs
are lower than budgeted, capacity factors are higher than estimated ((d) and (e) in Exhibit 32). In addition,
if the operator is able to use the awarded coal blocks as a source of fuel for other power projects – assuming
the coal blocks have greater reserves than is required for the UMPP – there is additional value to be had
from this source.
(iii) Independent Power Plants
Independent Power Producers operating unregulated power plants can bid into State Electricity Board
power purchase agreements held under competitive bidding processes, or sell into the merchant or spot
market. In either circumstance, the 2009 regulations are not relevant. As a result, the full risk and reward of
the operations are available to the independent power producer. Similarly, a UMPP that has met the
obligations under the terms of the UMPP off-take contract is permitted to sell into other markets.
Sell into Unscheduled Interchange in regional load dispatch centers ((f) above)
Finally, the regional load dispatch centers have, since 2004, operated an Unscheduled Interchange market
where – notwithstanding scheduled generation or dispatch instructions – any generator can sell into the
unscheduled interchange market at any time1. The pricing offered in the Unscheduled Interchange market is
set based upon imbalances between demand and supply in the regional grid.
The two primary performance characteristics of any electricity network are voltage and frequency. Voltage
- or capacity - is measured in volts and is generally likened to water pressure within a system of water
pipes. Frequency is measured in hertz. Frequency lacks a direct comparison within the water pipes analogy.
However, the simplifying intuition is the observation that electricity on an AC network travels in waves;
hertz is the measure of cycles per second. The Indian electricity network is set to operate at 50 Hz per
second.
Because electricity cannot be stored cost effectively, an electricity network relies upon demand (or load)
and supply (or generation) being roughly in balance all of the time. That matching of demand and supply
regulates frequency on the grid. To the extent that demand (electricity being withdrawn from the network)
and supply (electricity being sent into the network) are out of balance, the frequency of the network will
start to deviate from target frequency. As actual frequency deviates further from the target frequency,
damage to the network can occur. At low levels of deviation, this damage manifests itself as increased
wear-and-tear on the network. As the deviation increases, transformers start to blow up and the network
shuts down. Unless this shut-down is done in a controlled fashion, the instability can cascade across large
areas of interconnected grids.
The Unscheduled Interchange is intended to provide an incentive to power plants to increase generation
during periods when frequency on the grid is falling (i.e., demand is greater than supply). As the frequency
of the grid falls further below 50 Hz, the price paid per kilowatt increases by increment.
In summary, all utilities can sell into the regional Unscheduled Interchange markets, where pricing is set to
stabilize frequency on the regional AC power grids.
Implications for equity returns under each regulatory classification
In a high growth market, the most financially attractive asset class based on the above analysis appears
to be the mid-size independent power plants. These facilities are not regulated by the CERC Tariff
regulations and are therefore not tied to a "black-letter" rate of return. Further, unlike the UMPPs, the
operators of the mid-size independent power plants are not committed to a tariff rate set through the
competitive bidding process merely to gain the right to develop the project. On the downside, the returns
calculated in the analysis assume no cost overruns and no delays in construction. Without the implicit
sponsorship of the Ministry of Power, the mid-size IPPs are perhaps the asset class most susceptible to
planning and approval delays.
The financial attractiveness of the mid-size IPPs is premised on three assumptions: key assumptions: (i)
construction completed as planned; (ii) high utilization levels over the asset life; and (iii) a near absence of
spare capacity in the market pushing down electricity pricing. In short, this asset class is the most capable
of capturing out-sized returns during periods of tight supply and the most susceptible to poor performance
once spare capacity emerges in the grid.
The pricing environment and the cost of coal have little relevance to the returns of the regulated assets.
The only requirement for centrally-regulated utilities to achieve the "black-letter" rate of return is that they
are available for dispatch approximately 85% of the time. Setting aside revenues from Unscheduled
Interchange, actual energy sent out is not a relevant consideration for the centrally-regulated plants.
Similarly, the cost of coal has minimal impact on the returns of the regulated plants. To the extent that
actual heat rates are lower than operating norms prescribed by regulation, the plants are able to incorporate
in the energy charge the cost of coal that is not actually consumed.
Outperforming the regulated return on equity is an inherently unstable source of value creation – The
two sources of value creation for regulated plants come from outperforming operating norms or from
selling into the Unscheduled Interchange market. Operating norms are re-set on a regular basis.
Accordingly, outperforming these metrics becomes – almost by definition - harder over time. Not every
power station can be above average, and remaining above average gets harder over time.
UMPP projects include captive coal blocks or are located near ports to enable easy importation of coal.
As a result, fuel costs are either different from the CIL-set rates (in the case of importation) or are, in some
sense, an accounting fiction for backward integrated, "pit-head" power plants. To the extent that UMPPoperating
utilities are able to achieve coal production beyond the requirements of the UMPP, they are able
to direct the coal to other facilities. Reliance Power is currently looking for a location for a further facility
near the Sasan coal mine development. The value of this "free" coal is not been captured within the above
analysis. Further, to the extent that coal is less expensive to mine than to purchase from CIL, the captive
mines represent a further source of value for the UMPPs.
Valuation Methodology
Our valuation for NTPC of INR 190 is based on a two-stage dividend discount model, a Price/Forward
Earnings multiple, and a DCF valuation. In our DDM, we base our estimate of growth in stage 1 based on
the company's current dividend pay-out ratio, and our estimate of return on book equity given the
regulations that prescribe NTPC's returns. The second-stage of the model assumes a steep increase in the
dividend pay-out ratio as capital spending falls once supply and demand within the Indian power sector
comes into balance in the latter half of the decade. Growth in the second-stage of the dividend discount
model drops as a result. On a Price/Forward Earnings basis, we assign the three year historical multiple of
14.8x to our FY2012 EPS of INR 12.72. Our DCF valuation assumes a WACC of 10.1% and a terminal
growth rate of 3%.
Our valuation for Reliance Power of INR 100 is based on a DCF valuation, adjusted downward to reflect
concerns about the terms on which the company may raise additional equity. Reliance Power is still in the
early stages of commissioning its fleet of power plants. Earnings are currently dominated by interest and
investment income and accordingly provide little guide as the company's core business or sustainable longterm
earnings power. Further, given our pessimism about the pricing power of the non-regulated fleet in
India, we have decided against using sales-based valuation metrics. Accordingly, we are valuing Reliance
Power as a "Start-up" on a DCF valuation methodology.
Risks
The primary risk to our thesis on the India utilities is that electricity demand growth may be higher than we
anticipate or the level of newly commissioned power stations may be lower than anticipated. In other
words, the long-term demand-supply imbalance may continue indefinitely.
In addition, for NTPC significant changes in the regulation of the power sector, or a statutorily required
reduction in Government ownership in NTPC over a short timeframe, or a significant investment in foreign,
non- regulated, non-generation assets (all floated in India in the last six months) would have negative
implications for NTPC valuation, in our view.
The primary risk to our thesis on Reliance Power is that if the long-term demand-supply imbalance
continues indefinitely, Reliance Power's IPP fleet – once built – will operate at higher than anticipated
utilization levels and sell electricity at higher than anticipated prices. In that circumstance, commissioning
the fleet in full and on time with minimal additional equity and through the use of large amounts of
inexpensive debt financing would create value over the long term that is not currently reflected in our
valuation.
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Indian Utilities: Tepid, Bumpy & A Lot Less Crowded -
Reducing RPWR Target to INR100; Maintain Underperform
Highlights
The slowdown in Indian power consumption growth and declining merchant prices over the last year has
two broad implications for utilities: raising money to build new power stations will be more difficult and
political pressure to fix the "broken" distribution sector will increase. The first factor will play out
immediately; the second, over time. This places a premium on incumbency and a low cost structure. Among
the stocks we cover, the beneficiary should be NTPC. Implications for Reliance Power are less attractive.
India continues to suffer from a shortage of electricity. The low level of power consumption growth
and declining merchant prices reflect problems with the distribution sector more than a deceleration in
underlying demand growth. In any case, power consumption was up 4.3% in 2010; installed capacity was
up 8.0%; and merchant pricing is trending down. The good old days for the IPPs may now be over.
NTPC is the lowest cost provider of electricity in India. It is also the largest operator in India and has
almost all of its capacity locked up in long-term power purchase agreements with a regulated return on
equity of 15.5%. If power consumption growth in India is slowing (for whatever reason), NTPC stands to
benefit as (i) reduced investment in the sector will reduce competition for fuel and dispatch; (ii) the
company's regulated business is largely insensitive to merchant pricing.
We are maintaining our target price on NTPC at INR190. NTPC is currently trading at the lower end of
its long term average on a P/E or P/B basis. If the company is able to adjust its tax expense this quarter
so as to escape MAT liability, earnings growth for FY2011 should be INR11.24, up 6.1% Y/Y.
Reliance Power is stuck between a rock and a hard place. The company is rapidly developing its
projects yet – in our view - does not have the cash to execute its expansion plan into 2012 without
additional equity. Any sign that Reliance Power is slowing its development of new projects will be
interpreted as either a lack of confidence in the domestic power market or internal concern about the
company's finances (both clear negatives). In our view, the company is likely to raise more cash before
the end of 2011 – and, in some ways, the sooner the better given the deteriorating negotiation position
that a declining cash balance creates. However, the first half of 2011 looks like an unattractive time for
Indian companies generally and Reliance Power in particular to seek new equity.
We are lowering our target price for Reliance Power to INR100. The lowered valuation reflects the
deteriorating pricing environment and the limited range of options: Reliance Power cannot suspend
construction to preserve cash without a negative response from investors. Conversely, given the long-lead
times, the company cannot accelerate construction to bring earnings forward
Investment Conclusion
We rate NTPC Market-perform (NATP.IN, Target Price INR190). Given NTPC's regulated rate of return
business and the company's reluctance to enter a competitive bidding process for its generation capacity, we
believe that the upside to current valuation is limited.
We are lowering our target price for Reliance Power to INR100. We are maintaining our Underperform
rating. The lowered valuation reflects the deteriorating pricing environment and the limited options range of
options for the company: it cannot suspend construction to preserve cash or acceleration construction to
meaningfully bring earnings forward.
Reliance Power recently affirmed progress on over 20GW of coal-fired capacity and coal investment in
Indonesia. All this expansion requires cash. Reliance Power raised INR135.5 billion in its IPO in January
2008. Reliance Power has stated that – through project financing – it can lever its power stations 75%:25%
debt-to-equity. This effectively quadruples the amount of cash Reliance Power has had to spend on building
power stations to INR542 billion. To date, the company has spent INR122 billion and therefore has – at the
beginning of 2011 – an additional INR420 billion remaining to spend.
It is just now at the peak of its capital spending cycle. If Reliance Power is able to lever its balance sheet up
three times, this would suggest that funding may last until the approximately March 2012
In our view, the company is likely to raise more cash before the end of 2011 – and, in some ways, the
sooner the better given the deteriorating negotiation position that a declining cash balance creates. However,
the first half of 2011 is an unattractive time for Indian companies generally and Reliance Power in
particular to seek new equity.
And that is where the trouble starts. A deferral of negotiations with new equity investors in order to wait
for the stock to rebound increases the likelihood that the stark math painted above – where Reliance Power
is out of cash and out of sources of debt funding by beginning of 2012 – is the opening topic of
conversation.
Details
India has a chronic lack of electricity supply. Roughly 400 million people do not have access to electricity.
Indian power consumption per capita is ~1/3rd that of China. Yet the single best reason not to invest in the
Indian power sector is a simple one: everybody already knows this.
As has been widely reported, the Sensex had been the second-worst performing index in the world in 2011,
behind only Egypt (Exhibit 2). Concerns about inflation and the sustainability of economic growth in India
are driving the poor performance. Reliance Power is down 23.3% since January 1 and has underperformed
the Sensex by 1,240bps. NTPC is down 8.3% since January 1 although it has outperformed by 260bps
Since the beginning of 2010, NTPC, Reliance Power and Tata Power (BBG: TPWR; Not Covered) have all
underperformed the Sensex (Exhibit 4). The Sensex is up 4% since the beginning of January 2010.
There is (at the end of January 2011) 170GW of installed capacity in India. As we discuss in this report,
India's reputation as a difficult place to build and operate infrastructure is well earned. New capacity growth
at 8% in 2010 continues to lag announced plans and capacity expansion since the end of 1999 has grown at
a 5.5% CAGR
Even given clear demand, significant plans for capacity growth and the regulatory environment revised by
the Electricity Act 2003 to encourage expansion of the generation sector, this total capacity of newly
commissioned power stations over the last decade has been disappointing. The greatest annual increase in
installed capacity in India over the last decade came in 2007 when 13.4GW of new capacity was installed
Coal-fired generation dominates the power fleet, creating further problems in terms of coal
supply
Recently reported results have highlighted that distributing electricity to those who require it is - if anything
- more complicated than generating power. The Central Electricity Authority calculates and publishes
available and required electricity on a monthly basis (Exhibit 8). That deficit has been decreasing on a
year-on-year basis in recent months.
This slowdown in Indian power consumption growth over the last year relates to the state of finances at
State Electricity Boards more than an underlying drop in demand for electricity. The distribution sector
throughout most of India suffers from high levels of losses, or theft, of electricity. In some instances,
provision of electricity is, for a distribution company, a loss-making exercise as the cost of the units stolen
exceeds the profit from the electricity sold. In that circumstance, distribution companies (operated by the
State Electricity Boards that purchase electricity by the utilities) will – absent instruction to maintain supply
– simply shut down electricity supply at certain times of the day in order to limit losses.
There are two broad implications for the utilities sector if the poor state of the balance sheets of the
distribution companies rather than the underlying demand for electricity is the determining factors of power
consumption growth: raising money to build new power stations will be more difficult and political
pressure to resolve the "broken" distribution sector will increase.
The first factor will play out immediately; the second, over time. This place a premium on incumbency and
low cost. The long-term beneficiary in our view should be NTPC. In fact, for NTPC this is less of a
problem than for the rest of the industry. NTPC's fleet is largely regulated and gets paid a return on equity
for availability. For the rest of the industry, payment is – largely - based on electricity supply. Certainly for
the power stations that are being built currently by IPPs, the base case scenario has involved the ability to
sign long-term power purchase agreements at Rs3.50/KWh or more and to sell power into the merchant
market at Rs5-6/KWh or more. The merchant market has been trending down since 2008
The average price of merchant electricity since the middle of 2008 as reported by IEX India has been just
over Rs5/KWh. But the trend has been down the whole time. There is some seasonality involved: prices
tend to peak in the May-June time period and trough in January-February. We are currently therefore
emerging from a trough and the fact that the average three month price has been lower than the long-term
average since for the last six months is – in part – a function of seasonality.
But there is something else going on too. The peak in May-June 2010 was lower than the peak in 2009 and
the current trough is lower than the troughs in either 2010 or 2009. In short, merchant power prices are
falling.
Notwithstanding the low level of power consumption growth in India currently (4.3% in 2010) and the soft
merchant market, given that Indian GDP growth remains in the high single digits, it is unlikely that power
consumption growth can remain half of that level. The "classic" relationship between power consumption
growth and GDP growth suggests that developing economies use a lot of electricity for each additional unit
of GDP. The "power multiplier" doesn't generally fall below one until the economy is heavily
industrialized and is transitioning to services, transport and higher value-added manufacturing for its
sources of economic growth (i.e., the United States in the 1970s; China today). To suggest that India can
continue to growth at 9-10% with power consumption growth of 4-5% seems unlikely based on the state of
the Indian economy and this longstanding relationship between power consumption growth and GDP
growth.
And yet, that is what we have documented previously. Notwithstanding the fact that India would not be
viewed by many as a post-industrial economy, its power multiplier has been below 1.0 since 2003 (viewed
on a rolling five year basis).
Looking at the difference between real GDP and electricity consumption cumulative average growth rates
over the period from 1976 to 2009 highlights this inflection point (Exhibit 11). In no period before 2003
was real GDP growth (measured on a 5-year CAGR) greater than electricity production growth (measured
on a 5-year CAGR). In no period since 2003 has the inverse been the case. And if we look solely at data
since 2003, a new relationship between electricity production and real GDP growth appears to be emerging.
India's power multiplier has been ~0.7 for the past five years (Exhibit 12). Annual data has not yet been
released but the quarterly data suggests that the power multiplier for the five years ended December 2010
will be lower still.
There are (at least) three explanations for what is happening in India.
First, the low "power multiplier" is an aberration and if power delivery growth cannot increase, economic
growth rates will fall.
Second, India's economic development is not post-industrial but ex-industrial. That is, the heavy industry
growth phase that has been part of economic development everywhere since the Industrial Revolution will
simply get skipped in India for a lack of power – in the same way the country has "skipped" building copper
wires to every home in order to provide landline telephone service and instead jumped straight to ubiquitous
mobile phone usage. As a result, a power multiplier of 0.7 for a developing country is sustainable.
However, the definition of "developing" has to change.
Third – and most likely -power consumption growth will accelerate and the power multiplier in India will
increase over the next decade because of an increase in installed capacity and improved access to fuel
supply. Both of these things will, in our view, result in cheaper electricity that "funds" more powerintensive
activities.
Of course, all three outcomes are bad for the Indian power sector and – in particular – IPPs like Reliance
Power that are not CERC regulated.
Reliance Power: Arriving Late to the Party?
Reliance Power's net profit for the quarter ended December 31, 2010 (3QFY11) was INR 1,436M, 2.2%
below consensus estimates of INR 1,469M. Operations remain middling. Since the commencement of
Rosa's second unit in June 30, 2010, Rosa's generation has increased sequentially from 545.7 GWh
(2QFY11) to 713.9GWh (3QFY11). However, Rosa's utilization rate for 3QFY11 was 53.9%, below the
national thermal utilization of 69.7% and Private Sector IPP thermal utilization of 64.4%.
But for Reliance Power, operating result is now a tertiary consideration. The key questions are (i)
commissioning dates for projects under construction and (ii) the rate of cash consumption.
In terms of the commissioning timeline, Reliance Power confirmed this week that the company is planning
to commission the Samalkot gas-fired power stations by the end of the year and that the Sasan and Tilaiya
coal mines are on-track. The company also affirmed progress on over 20GW of coal-fired capacity and coal
investment in Indonesia.
All this expansion requires cash. Reliance Power raised INR135.5 billion in its IPO in January 2008.
Reliance Power has stated that – through project financing – it can lever its power stations 75%/25% debtto-
equity. This effectively quadruples the amount of cash Reliance Power has had to spend on building
power stations to INR542 billion. To date, the company has spent INR122 billion and therefore has – at the
beginning of 2011 – an additional INR420 billion remaining to spend, including INR2B of accumulated
EBITDA contribution. Reliance Power is just now at the start of peak capital spending.
By the end of FY2011, commissioning for the first units of Rosa Phase II, Butibori and the Samalkot will
have started, which will increase total installed capacity to ~5,400MW by December 2012.
The rough math is simple: ~30GW of thermal power stations requires ~USD30B in India. The total funding
capability based on the IPO raise and the 75%/25% debt-to-equity target is INR542 billion (USD12 billion).
Cash flow from operations from the early projects will fund construction of the later projects. Timing
matters. And the company has discussed a need for more equity at some point. The question is: when?
The company obtained approval from shareholders to raise additional equity in September 2010. We
believe this equity raise may occur before the end of 2011. The recent drop in Reliance Power's share price
makes this an extremely unattractive time to raise new equity. Accordingly, cash burn is all important.
Reliance Power is stuck between a rock and a hard place: any sign that it is slowing its development of new
projects (Exhibit 13) will be interpreted as either a lack of confidence in the domestic power market or
concern about the company's financial position (both are obviously negative). At the same time, the first
half of 2011 is shaping up for a variety of reasons to be an unattractive time for Reliance Power to raise
more cash. Shares in Reliance Communications and Reliance Infrastructure have both dropped ~30% and
~25% respectively since January 1 on various negative media reports including – as recently as February 16
– Anil Ambani's being investigated by the Indian Central Bureau of Investigation over the allocation of the
2G spectrum. Reliance Power's share price has also come under pressure.
Based on company guidance, we use a rough estimate of USD1B in capital costs for 1GW of installed
capacity. We assume some savings for the expansion of the Sasan, Krishnapatnam and Tilaiya Ultra-Mega
Power Plants (USD800M/GW). We also assume a straight line capital spending pattern for two years prior
to the commissioning of the power station. The implied capital spending cycle is therefore rough. Without
the aid of a recent balance sheet or cash flow statement from the company, it is not possible to confirm the
precise timing of spending estimates. However, by our calculations, Reliance Power is approaching the
peak of its capital spending cycle currently
Levering book equity three times suggests available funding at December 31, 2010 may have been
INR420B, assuming total capital spending (all-time) to the end of 2010 was INR122B
If Reliance Power is able to lever its balance sheet up three times, this would suggest that funding may last
until the approximately March 2012 (Exhibit 18). At that point, access to funding would be exhausted but
only Butibori, Rosa, Samalkot, Goa and Kochi would be commissioned (~3.3GW of capacity
However, there is – in our view – a problem with the assumption that Reliance Power can lever up its entire
balance sheet to three times the level of book value of equity. First, Reliance Communications' stock
(BOM:532712, Not Covered; another part of the Reliance ADAG group) is down ~30% YTD because of –
among other things – its increasing debt load (Exhibit 21). We believe that – given the lackluster growth in
power consumption and softening merchant prices - Reliance Power may struggle to raise additional debt to
bring its debt/equity ratio up to this level. And if it does – through the project financing arrangements
already in place - we believe that the stock price may well come under further pressure from investors. The
level of leverage required to get Reliance Power through to the first half of 2012 before additional cash is
needed would place Reliance Power among the most heavily geared publicly companies in India (
In short, the assumption that Reliance Power can get to the start of 2012 before it requires more cash is
based on the fact it can lever up all of the cash it has raised three times. If – by virtue of debt covenants or
for any other reason – Reliance Power cannot lever in the manner that it has guided, the cash will run out
sooner.
The Danger of Just-in-Time Financing
Burn rate is an important consideration for Reliance Power given that we believe the company will need to
raise additional equity in order to continue its capital program into 2012.
On August 12, Reliance Power filed a notice with the National Stock Exchange announcing it was seeking
shareholder approval to – among other things - raise more funds by issuing equity shares to Qualified
Institutional Buyers and through issuing securities in international markets. The resolution allows Reliance
Power to raise equity from Qualified Institutional Buyers by an amount that does not result in an increase in
shares then outstanding of more than 15%. The international issuance provision has a similar clause of up to
10%. Pricing of the new equity is in both instances in the absolute discretion of the board. The resolution
was approved by shareholders through postal ballot and announced in September 2010.
The mechanism to raise more equity is therefore entirely in the hands of Reliance Power's board. But given
that the very mention of available funding is likely to set a very low floor on pre-money valuations, it is
generally in the interests of a company in Reliance Power's position to initiate discussions with new
investors as soon as possible. Of course, given what has happened to the stock in the last few weeks, it is in
Reliance Power's interests to delay these discussions for as long as possible.
And that is where the trouble starts. A deferral of negotiations with new equity investors in order to wait
for the stock to rebound increases the likelihood that the stark math painted above – where Reliance Power
is out of cash and out of sources of debt funding by beginning of 2012 – is the opening topic of
conversation.
In that instance, the discounted value of the company's future cash flows is of significantly less interest than
the break-up value of the company's existing assets. And that discussion is unlikely to go well for Reliance
Power. Specifically, it is a relatively simple matter to value the operating power stations at Rosa, Samalkot,
Goa and Kochi (based on NTPC's enterprise value, roughly USD1.2B per GW). But the fact that the
conversation is occurring at all means that cash balances and investments are likely to have dwindled. That
leaves the partially built power station fleet – Sasan, Butibori, Krishnapatnam, Tilaiya and Chitrangi - and
the expansions at Rosa and Samalkot.
Depending on whether you are the buyer or the seller, determining the value for a partially completed
power station in a market with 126GW of capacity currently under construction and an additional 408GW
in planning is either very difficult or extremely simple. For the buyer, the value is approximately zero
given that – with installed capacity growth in 2010 roughly 2x power consumption growth, it is a buyer's
market. For the seller, the perspective will obviously be different. However, the answer is unlikely to be
greater than 1x the cost of construction to date.
It is in Reliance Power's interests to avoid discussions where the break-up value of the company is one of
the parameters for assigning a valuation. And that means raising equity sooner rather than later. Our revised
valuation for Reliance Power is based on a discounted cash flow analysis assuming a 25% increase in the
shares currently outstanding. The valuation is INR100
NTPC: Damn the Taxation, Full Steam Ahead
NTPC is the lowest cost provider of electricity in India. It is also the largest and the best operator in India
and has almost all of its capacity locked up in long-term power purchase agreements.
Yet, in the third quarter of 2010, NTPC reported that several of its power stations were backed down
because of the refusal of various State Electricity Boards to pay for the electricity that would have been
generated. In the first nine months of the financial year (April-December 2010), NTPC estimates that it
could have generated an incremental 10,000 GWh or roughly 6% of gross generation over the period.
NTPC offers the cheapest electricity supply in India. By virtue of the regulations under which NTPC
operates and the long-term power purchase agreements that it signs with the State Electricity Boards
("SEBs"), the SEBs are liable for all of NTPC's fixed costs and a return on equity of ~15.5% as long as
NTPC is available for dispatch more than 85% of the time.
There are two implications here. First, as long as NTPC is available for dispatch, its earnings are largely
unaffected by the decision of a particular SEB not to purchase electricity. There are additional benefits to
NTPC from operating at high utilization because of the way the CERC regulations are drafted. Because it
is able to generate electricity at a heat rate that is lower than the nominal heat rate in the electricity
regulations, NTPC effectively gets paid for coal that it does not burn. However, if NTPC doesn't generate
the electricity, it cannot capture this benefit. And backing down and re-firing coal-fired power plants is
inefficient. In short, the actions of the SEBs matter in terms of quarterly earnings – but only at the margin.
Second (and more broadly), if State Electricity Boards cannot afford to pay the variable cost component of
NTPC's electricity generated from domestic coal (by our estimate, less than Rs1.50/KWh), long-term
prospects for IPPs building power stations that will import coal based on business cases that assume a
payment of Rs3.50KWh (at a minimum) are bleak
And the poor operating performance of NTPC's power stations is clear from a review of the rolling gross
generation growth over the last twelve months. Rolling annual gross generation growth is currently 1.4%
for NTPC (Exhibit 23). To put that in context, annual energy demand growth in India has been 5-7% in
recent years and installed capacity growth was 8% in 2010 and is trending higher in 2011. Low power
consumption growth rates in India are often attributed to a lack of capacity growth or a lack of coal. In this
instance, capacity is not the problem. For NTPC, utilization has fallen in two of the last three quarters and
was flat in the second quarter
Coal provision from imports and Coal India has increased modestly over the last year. Total coal increased
from 98.58 million tons in the nine months to December 2009 to 100.44 million tons in the nine months to
December 2010 – a 1.8% increase.
The bad news in relation to NTPC is now all out: the company is currently flirting with the Minimum
Alternate Tax regime which would serve to lower earnings by limiting the amount of notional tax expense
the company can recover from State Electricity Boards pursuant to its Indian electricity pricing regulation.
Commissioned power stations in the 2011 financial year will disappoint once again. Finally, demand for
NTPC's electricity – the cheapest in India – fell in the most recent quarter.
But the bad news is temporary and understood. The good news has longer term implications. The company
has set the goal of signing up as much capacity under long-term power purchase agreements regulated by
the CERC pricing mechanism (which prescribed a 15.5% return on regulated equity) as it could. In the
third quarter, the company announced it had signed up 100GW under this pricing mechanism which would
take NTPC until 2020 to build out (
It has been difficult to understand the rationale for signing up new capacity under the CERC regulations
when NTPC is the lowest cost producer in a tightly supplied market with competitive bidding available.
However, if – as is now the case – power consumption growth is lower than installed capacity growth, the
near-guarantee of a 15.5% return on regulated equity is increasingly attractive.
Of course, having signed up the long-term power purchase agreements is one thing; building the power
stations is another. And NTPC's track record has been poor. The company's guidance of 4,150MW of new
installed capacity in the financial year ended March 31, 2011 has been lowered to 3,150MW. The
compounding annual growth rate of new installed capacity between March 2005 and March 2010 was
4.2%. On that front, the current financial year may be an inflection point as 3,150MW is an 11% increase
from the end of March 2010. However, to reach a target of 100GW by March 2020, NTPC will need to
expand installed capacity at a 13.5% CAGR for a decade
Assuming that NTPC maintains availability well above 85% (and therefore can over-recover its fixed
costs), uses 70% debt to finance its expansion, maintains a steady level of income from investment sources,
and operates at a high plant load factor so that it can over-recover fuel costs, earnings over the next decade
could also expand at a rate in excess of 10% without undue reliance on other income, unscheduled
interchange or over-recoveries (Exhibit 26 and Exhibit 27).
NTPC Valuation
Given that the company's return on equity per power station is prescribed, the dividend pay-out ratio has
been steady for the last five years and the industry is heading towards a state of overcapacity in our view,
we use a two-stage dividend discount model for valuation. NTPC's dividend pay-out range is clear from the
last five years and can be expected to hold steady while India's power generators go through a period of
rapid capacity expansion. At the end of that expansion period, India's power sector – including NTPC –
should be able to grow no faster than the broader economy or nominal GDP. That transition is, in our view
likely to occur at the end of this decade.
We assume that NTPC maintains the current low dividend payout levels up through a terminal year, after
which time the company dividends out the majority of earnings as expansion opportunities dry up (Exhibit
28).
To implement this dividend discount model, Stage 1 dividends (FY2012-2020) are valued using the formula
for present value of a growing annuity: PV = D/(i-g)[1 – ((1+g)/(1+i))n]. The payment in the initial period is
our estimate for the dividend in 2012, the discount rate is the cost of equity, time period runs from 2012 to
2020 and the growth rate is calculated as Growth rate = (1 – Pay-Out ratio) x Return on Equity. In Stage 2,
the terminal value of the dividends equals the present value of a growing perpetuity PV = D/(COE – g)
starting from the end of 2020 where the initial period payment is the dividend in 2021.
Earnings cannot grow faster than the rate at which the company re-invests (1-Pay-out ratio) multiplied by
the return on equity. When the dividend pay-out ratio are stable over time and return on equity is stable and
known, the observation ceases to be theoretical and takes on practical application. In short, with an
approximately 35% dividend pay-out ratio and a 16% return on equity, growth will be approximately 10.4%.
Extending that insight into Stage 2, a given perpetual growth rate implies a corresponding pay-out ratio
since NTPC's returns on equity will remain fixed.
We employ a return on equity of 16% through both stages of the model, extend the dividend pay-out ratio
for 2009 through Stage 1 (implying a growth rate of 10.4%) and assume a perpetual growth rate of 3%
starting from 2021 (implying a dividend pay-out ratio of 81.25%). Furthermore, we apply the calculation of
NTPC's cost of equity, where risk-free rate is the yield on Reserve Bank of India Reverse Repo rate, beta is
the two-year raw beta as compiled by Bloomberg and the risk premium is calculated based on the difference
between the implied cost of equity of the Bombay Stock Exchange Index (Sensex) and the risk-free rate.
We use a cost of equity of 11.75% derived from the Reserve Bank of India Reverse Repo yield of 5.25%, a
market premium of 10.09% and a beta of 0.644.
Rather than using the long term Indian government bond yield as our risk free rate, we use the Reserve
Bank of India Repo yield because Indian bond yields have traditionally been high due to inflation
expectations. The CPI in India is currently growing at approximately ~12% annually. Since we do not
account for inflation in our growth projections, we use a short-term risk free rate that does not incorporate
inflation expectations.
We use historical beta (two-year raw beta) as compiled by Bloomberg. To the extent that a company enters
a new business; fundamentally changes its supply chain or customer base; or is subject to a dramatic change
in market structure, it is certainly possible to argue that a non-historical beta is warranted. None of those
things have happened.
Finally, we are using a country equity risk premium for India of 10.09%. This figure was derived
subtracting the risk-free rate described above from the implied cost of equity of 14.0% that the market
attributes to the Bombay Stock Exchange Index. This market cost of equity was calculated using the
modified Gordon Growth formula P/E = (1-g/ROE)/(Ke-g), where P/E is calculated as the price per share of
the index over its forward EPS, g is India's average annual nominal GDP growth and ROE is forward EPS
over historical BVPS. Adjusting market risk equity premium, the upside to valuation remains limited.
Given that NTPC is free cash flow positive, we also prepare a discounted cash flow valuation using the
same cost of equity components as the dividend discount model above
Understanding the Indian Regulatory Environment
The discussion below provides background on the Indian regulatory environment for power generation. In
general, an electricity generation asset in India may fall into one of four regulatory schemes:
Central Electricity Regulatory Commission ("CERC") regulation, issued pursuant to Sections 62 and
79 of the Electricity Act of 1993 ("the Act");
State Electricity Board regulation, issued pursuant to Section 62 and 82 of the Electricity Act;
Ultra Mega Power Plant regulation issued pursuant to Section 63 of the Act; or
Independent Power Plant status, pursuant to Section 63 of the Act;
In addition, all power stations can sell electricity into the Unscheduled Interchange system.
The generation, transmission and distribution of electricity in India is largely regulated by the Electricity
Act 2003. The Act aims to develop the industry, promote competition, protect supply of electricity to all
areas and promote environmentally benign policies. For current purposes, the key aspects of the electricity
reforms introduced in 2003 are: competitive generation (any company can establish, operate and maintain a
generating station without a license, as long as the station complies with prescribed technical standards
relating to grid connectivity – and obtaining land, water use and other permits as required by separate
legislation); captive generation; and open access.
Further, the Act contemplates two means by which centrally-regulated power generation companies may be
paid for electricity produced – either through tariffs prescribed under section 62 of the Act (and set out in
the CERC regulations issued in January 2009 ("the 2009 regulations"), or via a competitive bidding
process. This competitive bidding process falls into two categories: either Case I where power stations bid
to supply electricity or Case II, where power generation companies bid to build and operate power stations
with a prescribed PPA attached from the outset. Ultra Mega Power Projects are an example of the Case II
process.
The CERC regulations and the State Electricity Board regulations provide heavily detailed prescriptions for
how operating costs, fuel costs and return on equity are to be calculated and recovered. In short, the utility
is able to pass through taxes, interest expense, fuel costs and operating expenses to the purchaser and
achieve a return on regulated equity as long as the utility meets set performance criteria.
Ultra Mega Power Projects are large-scale projects where the central government has coordinated land,
water usage, transmission, environment approvals and fuel source requirements and offers the projects on a
competitive basis to developers to build and operate through long term contracts. Developers then bid for
the right to develop and operate the projects based on a levelized cost of energy over the course of the
plant's life. The return on equity is determined by the developer and is capped only by (i) the developer's
ability to commission the power station on schedule and within budget; and (ii) the "winner's curse" implicit
in any competitive bidding scenario where the return on equity of the winning bid will tend to be lower than
those of the unsuccessful submissions.
Independent Power Plants enter long-term power purchase agreements with State Electricity Boards, and
sell to the merchant or spot market. These contracts are entered without reference to a prescribed return on
equity.
For the centrally regulated power stations, UMPPs and IPPs, creating value occurs through one of six ways
(i) CERC-regulated Generation Assets
The CERC regulations provide a heavily detailed prescription for how operating costs, fuel costs and return
on equity are to be calculated and recovered. In short, the utility is able to pass through taxes, interest
expense, fuel costs and operating expenses to the purchaser and achieve a return on regulated equity as long
as the utility meets set performance criteria.
The financial performance of generation assets falling under the CERC 2009 regulations tops out at return
on equity in the low 20% range, (assuming 70:30 debt-to-equity), regardless of coal costs and the pricing
environment. However, returns at this level assume that the company can over-recover its costs under the
regulations through fuel efficiency levels and availability above prescribed operating norms. It is important
to note that tightening of the operating norms prescribed through the regulations would result in a
curtailment of returns for regulated assets back to the "black-letter" rate.
Mechanically, the regulations contemplate separate payment of capacity charges covering fixed costs;
energy charges covering fuel costs. Unscheduled Interchange charges are paid through a separate
mechanism outside of the 2009 regulations.
The regulations are intended to ensure that power stations seek to maximize the amount of time during the
year that they are available for dispatch without penalizing the stations for the fact that they may not in fact
be dispatched. Returns on equity are – up to the black letter rate of 15.5% - entirely within the control of
the individual station operator without reference to the broader sector issues of transmission, distribution
and load.
Under the 2009 regulations, an after-tax return on equity of 15.5% is permitted, assuming prescribed
performance criteria are met. An additional 0.5% return on equity is permitted for projects commissioned
after April 1, 2009 and completed on time.
The equity in any project entering commercial operation after April 2009 is deemed in the 2009 regulations
to be 30% of the capital cost. The actual equity above this level is treated as a normative loan (clause 12).
For generating stations entering commercial operation before April 2009, the earlier regulations apply to set
equity and normative loans. The 2004 regulations set a debt-equity ratio of 70:30 for all generating stations
(clause 20; 2004 regulations). Interest on the normative loan is deemed to be (absent specific project
financing) the weighted average interest rate for the entire company.
The three primary drivers of return for the CERC-regulated plants above the black letter rate are set out
below.
Over-recovery of Fixed Costs by exceeding Normative Annual Plant Availability Factor ((a) above)
Utilities with regulated assets subject to the 2009 CERC regulations can over-recover their fixed costs if
plant availability throughout the year is higher than the normative annual plant availability factor set out in
the 2009 regulation. This over-recovery results in an effective return on equity higher than the "black-letter"
rate.
Under the 2009 regulations, power plants recover their fixed costs based on the amount of time during the
relevant period that the power plant is available to generate electricity. These fixed costs are adjusted by a
ratio of actual to normative availability to produce the capacity charge the plant is permitted to recover
through pricing.
This over-recovery mechanism replaces an incentive structure in the 2004 regulation where incentive
payments were made if energy sent out during scheduled generation periods exceeded a prescribed plant
load factor. The change effectively ensures that power plant owners are rewarded for maintaining their fleet
in a state of availability (something that the owner can control) rather than rewarding the owner for dispatch
(which the owner cannot control).
In summary, assets falling within the scope of the 2009 regulations are able to over-recover fixed costs by
exceeding Normative Annual Plant Availability Factors.
Incentive Payments achieved by exceeding Plant Load Factor ((b) above)
While the 2004 regulations are no longer applicable, much of the state regulation that remains in force –
specifically, in Delhi and Maharashtra - still reflects the mechanics set out in the 2004 regulations –
including the incentive payment.
Under the 2004 regulations, power plants were permitted to recover their fixed costs in full and, in some
cases, claim an incentive payment, for exceeding a prescribed target plant load factor. The plant load factor
expresses the amount of electricity that the power station is scheduled to generate as a percentage of total
potential generation at nameplate capacity, adjusted for house consumption. An incentive payment is
available for each scheduled kilowatt/hour sent out above the target plant load factor.
The 2004 regulations linked incentives to coordination of electricity generation with scheduled generation.
This mechanism was designed to alleviate the flaw in previous regulation that encouraged power plants to
operate at times where there was no demand (or load) simply in order to recover fixed costs. That strategy is
rational within a regulatory construct that pays for total electricity sent out but is often detrimental to load
balancing and network stability (discussed in (f) Unscheduled Interchange below). The 2009 regulations go
a step further by decoupling the recovery of fixed costs from energy generation altogether. Instead, plants
are rewarded for being available to generate electricity, regardless of total electricity generated.
In summary, assets falling within the scope of the state electricity generation regulations in, among other
states, Maharashtra and Delhi, are able to obtain incentive payments by exceeding Plant Load Factor.
Over-recovery of fuel cost if plant gross heat rate is below normative gross heat rate ((c) above)
Utilities with regulated assets can over-recover fuel costs if their plants operate at heat rates lower than the
normative heat rates prescribed by regulation. Heat rates are expressed in kilocalories per kilowatt/hour and
reflect the energy input required to generate one kilowatt/hour of electricity (gross). In short, the heat rate
reflects how much coal is needed to run the power station at a given level of output for a given period of
time. Lower heat rates reflect more efficient power stations that use less fuel. Regulated power stations
recover fuel costs based on normative heat rates. Thus, if the actual heat rate is below the normative heat
rate, under the regulations a power station is able to "recover" the cost of coal that it has not burned.
Under the 2009 regulations, fuel costs are recovered as energy charges. However, rather than a strict passthrough
of the cost of fuel purchased or consumed, the energy charge is calculated based upon normative
inputs. Specifically, the energy charge is calculated on a per kilowatt/hour basis based upon and adjusted
for the following:
A prescribed gross heat rate for existing power plants, or the design heat rate for new power plants,
The normative auxiliary consumption of electricity; and
The normative consumption of secondary fuel and limestone.
In short, rather than passing through the actual fuel cost, the regulations allow for a recovery of fuel costs
based on the price of fuel and estimates of fuel consumption given energy produced. An over-recovery of
fuel cost is therefore available to the extent that:
The actual heat rate of the power station is less than the design or prescribed heat rate,
The house consumption of electricity is less than the normative auxiliary rate; and
The actual consumption of secondary fuel and limestone is less than the normative consumption.
Of course, to the extent that the actual levels are greater than normative levels, the utility will under-recover
its fuel cost. Accordingly, the regulation implicitly encourages efficient use of resources and retirement of
inefficient power stations.
In summary, assets falling within the scope of the 2009 regulations are able to over-recover fuel cost if
plant gross heat rate is below the normative gross heat rate.
Similarly, the 2009 regulations set normative operating costs. If a power station operates at costs below the
normative level, this represents a source of value creation for the generator.
(ii) Ultra Mega Power Plants
Section 63 of the Act requires the CERC and the SEBs to disregard the prescription set out in the
regulations issued under section 62 of the Act (e.g., the 2009 regulations described above) and adopt any
tariff if that tariff has been determined through a transparent process of bidding. The Ultra Mega Power
Plant ("UMPP") program operates under this provision.
The UMPP program has superseded the Mega Power Plant program established in the 1990s to encourage
private investment in power plants of 1,000MW capacity or larger. The UMPP program is focused on
projects to develop power facilities of 4,000MW or larger and includes a Ministry of Power-facilitated fasttrack
program for these large scale power projects. The Ministry of Power acquires land, obtains water
rights from the relevant state government, allocates fuel linkages or coal blocks, appoints consultants for
environmental assessments, obtains various other approvals and statutory clearances and secures contracts
for the sale of power in compliance with section 63 of the Act.
The fast-tracking is intended to remove the investment risk surrounding the development of large scale
projects in India and to entice large infrastructure developers and independent power producers to invest.
The competitive bidding process involves various developers submitting a levelized cost of energy
(expressed as an annual tariff over the 25 year period of the UMPP contract). The UMPP is awarded to the
lowest priced, qualified bid. The levelized cost of energy bid is generally lower for the UMPPs than pricing
in long-term contracts with other Independent Power Plants given the scale of the UMPPs, the secured fuel
source and the significant legwork that the Ministry of Power has invested in these projects before they are
awarded to developers.
The opportunity to exceed the "black-letter" return on equity for the UMPPs is clear: the "black-letter"
return does not apply. The UMPPs are not governed by the 2009 (or the 2004) regulations. The developer
is able to set financial metrics to whatever level desired. However, the successful bidder will tend to be the
bidder with the lowest equity returns.
Additional value can be created by the developer/operator to the extent that construction and operating costs
are lower than budgeted, capacity factors are higher than estimated ((d) and (e) in Exhibit 32). In addition,
if the operator is able to use the awarded coal blocks as a source of fuel for other power projects – assuming
the coal blocks have greater reserves than is required for the UMPP – there is additional value to be had
from this source.
(iii) Independent Power Plants
Independent Power Producers operating unregulated power plants can bid into State Electricity Board
power purchase agreements held under competitive bidding processes, or sell into the merchant or spot
market. In either circumstance, the 2009 regulations are not relevant. As a result, the full risk and reward of
the operations are available to the independent power producer. Similarly, a UMPP that has met the
obligations under the terms of the UMPP off-take contract is permitted to sell into other markets.
Sell into Unscheduled Interchange in regional load dispatch centers ((f) above)
Finally, the regional load dispatch centers have, since 2004, operated an Unscheduled Interchange market
where – notwithstanding scheduled generation or dispatch instructions – any generator can sell into the
unscheduled interchange market at any time1. The pricing offered in the Unscheduled Interchange market is
set based upon imbalances between demand and supply in the regional grid.
The two primary performance characteristics of any electricity network are voltage and frequency. Voltage
- or capacity - is measured in volts and is generally likened to water pressure within a system of water
pipes. Frequency is measured in hertz. Frequency lacks a direct comparison within the water pipes analogy.
However, the simplifying intuition is the observation that electricity on an AC network travels in waves;
hertz is the measure of cycles per second. The Indian electricity network is set to operate at 50 Hz per
second.
Because electricity cannot be stored cost effectively, an electricity network relies upon demand (or load)
and supply (or generation) being roughly in balance all of the time. That matching of demand and supply
regulates frequency on the grid. To the extent that demand (electricity being withdrawn from the network)
and supply (electricity being sent into the network) are out of balance, the frequency of the network will
start to deviate from target frequency. As actual frequency deviates further from the target frequency,
damage to the network can occur. At low levels of deviation, this damage manifests itself as increased
wear-and-tear on the network. As the deviation increases, transformers start to blow up and the network
shuts down. Unless this shut-down is done in a controlled fashion, the instability can cascade across large
areas of interconnected grids.
The Unscheduled Interchange is intended to provide an incentive to power plants to increase generation
during periods when frequency on the grid is falling (i.e., demand is greater than supply). As the frequency
of the grid falls further below 50 Hz, the price paid per kilowatt increases by increment.
In summary, all utilities can sell into the regional Unscheduled Interchange markets, where pricing is set to
stabilize frequency on the regional AC power grids.
Implications for equity returns under each regulatory classification
In a high growth market, the most financially attractive asset class based on the above analysis appears
to be the mid-size independent power plants. These facilities are not regulated by the CERC Tariff
regulations and are therefore not tied to a "black-letter" rate of return. Further, unlike the UMPPs, the
operators of the mid-size independent power plants are not committed to a tariff rate set through the
competitive bidding process merely to gain the right to develop the project. On the downside, the returns
calculated in the analysis assume no cost overruns and no delays in construction. Without the implicit
sponsorship of the Ministry of Power, the mid-size IPPs are perhaps the asset class most susceptible to
planning and approval delays.
The financial attractiveness of the mid-size IPPs is premised on three assumptions: key assumptions: (i)
construction completed as planned; (ii) high utilization levels over the asset life; and (iii) a near absence of
spare capacity in the market pushing down electricity pricing. In short, this asset class is the most capable
of capturing out-sized returns during periods of tight supply and the most susceptible to poor performance
once spare capacity emerges in the grid.
The pricing environment and the cost of coal have little relevance to the returns of the regulated assets.
The only requirement for centrally-regulated utilities to achieve the "black-letter" rate of return is that they
are available for dispatch approximately 85% of the time. Setting aside revenues from Unscheduled
Interchange, actual energy sent out is not a relevant consideration for the centrally-regulated plants.
Similarly, the cost of coal has minimal impact on the returns of the regulated plants. To the extent that
actual heat rates are lower than operating norms prescribed by regulation, the plants are able to incorporate
in the energy charge the cost of coal that is not actually consumed.
Outperforming the regulated return on equity is an inherently unstable source of value creation – The
two sources of value creation for regulated plants come from outperforming operating norms or from
selling into the Unscheduled Interchange market. Operating norms are re-set on a regular basis.
Accordingly, outperforming these metrics becomes – almost by definition - harder over time. Not every
power station can be above average, and remaining above average gets harder over time.
UMPP projects include captive coal blocks or are located near ports to enable easy importation of coal.
As a result, fuel costs are either different from the CIL-set rates (in the case of importation) or are, in some
sense, an accounting fiction for backward integrated, "pit-head" power plants. To the extent that UMPPoperating
utilities are able to achieve coal production beyond the requirements of the UMPP, they are able
to direct the coal to other facilities. Reliance Power is currently looking for a location for a further facility
near the Sasan coal mine development. The value of this "free" coal is not been captured within the above
analysis. Further, to the extent that coal is less expensive to mine than to purchase from CIL, the captive
mines represent a further source of value for the UMPPs.
Valuation Methodology
Our valuation for NTPC of INR 190 is based on a two-stage dividend discount model, a Price/Forward
Earnings multiple, and a DCF valuation. In our DDM, we base our estimate of growth in stage 1 based on
the company's current dividend pay-out ratio, and our estimate of return on book equity given the
regulations that prescribe NTPC's returns. The second-stage of the model assumes a steep increase in the
dividend pay-out ratio as capital spending falls once supply and demand within the Indian power sector
comes into balance in the latter half of the decade. Growth in the second-stage of the dividend discount
model drops as a result. On a Price/Forward Earnings basis, we assign the three year historical multiple of
14.8x to our FY2012 EPS of INR 12.72. Our DCF valuation assumes a WACC of 10.1% and a terminal
growth rate of 3%.
Our valuation for Reliance Power of INR 100 is based on a DCF valuation, adjusted downward to reflect
concerns about the terms on which the company may raise additional equity. Reliance Power is still in the
early stages of commissioning its fleet of power plants. Earnings are currently dominated by interest and
investment income and accordingly provide little guide as the company's core business or sustainable longterm
earnings power. Further, given our pessimism about the pricing power of the non-regulated fleet in
India, we have decided against using sales-based valuation metrics. Accordingly, we are valuing Reliance
Power as a "Start-up" on a DCF valuation methodology.
Risks
The primary risk to our thesis on the India utilities is that electricity demand growth may be higher than we
anticipate or the level of newly commissioned power stations may be lower than anticipated. In other
words, the long-term demand-supply imbalance may continue indefinitely.
In addition, for NTPC significant changes in the regulation of the power sector, or a statutorily required
reduction in Government ownership in NTPC over a short timeframe, or a significant investment in foreign,
non- regulated, non-generation assets (all floated in India in the last six months) would have negative
implications for NTPC valuation, in our view.
The primary risk to our thesis on Reliance Power is that if the long-term demand-supply imbalance
continues indefinitely, Reliance Power's IPP fleet – once built – will operate at higher than anticipated
utilization levels and sell electricity at higher than anticipated prices. In that circumstance, commissioning
the fleet in full and on time with minimal additional equity and through the use of large amounts of
inexpensive debt financing would create value over the long term that is not currently reflected in our
valuation.
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