Carrier & Content Segregation: A Roadmap for Power sector reform

 

While unbundling of generation and transmission sector happened long ago, the distribution sector unbundling has been a non-starter. Now and then efforts made for discom privatization could not gather support because it was in form of replacement of public monopoly with private monopoly. Access to affordable quality power availability will remain a dream only till distribution sector is exposed to competition. Only competition is expected to provide consumers with choice of supplier, affordable and reliable power. All other network businesses like telecom, DTH etc have already been unbundled and It is high time that distribution sector is also unbundled separately into distribution (carrier) and Supply (content) so that private and public players can compete with each other to bring in efficiency and transparency.

The last serious efforts to unbundle distribution were made in 2014 by the ministry of Power through draft amendment bill for amending The Electricity Act. The draft bill reached the then standing committee headed by Shri Kirit Somaiya. While the committee was broadly supportive of the reforms, it gave few suggestions like providing flexibility to the states, transparent handling of existing discom PPAs, address consumer’s concerns, universal service obligation etc. Somehow, no progress could be made after that. However, C&C segregation still remains a low hanging fruit for reforms and could be a win-win for all  stakeholders, namely the consumers, the discoms and the government.

C& C segregation involves separation of the function of supply of electricity from the business of distribution of electricity and hence 2 licensees, namely Distribution licensee, for providing non-discriminatory access to their distribution network system on payment of regulated network access charges; and Supply licensees, competing with each other to supply electricity to consumers in a particular area and use the distribution system for such purpose

As pre-requisite for segregation of C&C business of incumbent discom, appropriate amendments are required in the Electricity Act.  Further, assets & accounts of incumbent discom is also required to be separated into distribution & supply functions. However, this is only possible after attaining 100% metering of all consumers/ feeders/ substations & distribution transformers.

Existing PPA portfolio of incumbent distribution licensee Is also required to be frozen and transferred to an intermediary company backed by the government. This Intermediary company should be responsible for working as a counterparty to all existing PPAs, selling power procured through these PPAs through the existing wholesale market / trading /exchange; and socialising all profits/ losses through a universal charge/ payment to all existing suppliers according to a pre-agreed formula say weighted average cost of power procured.

Separate Licensing

Separate distribution & supply licenses be provided by the SERCs after effective date of notification of new amendments and existing licenses of incumbent distribution licensee to continue only till its expiry or renewal, whichever is earlier. On expiry of term, the incumbent distribution license needs to be split into separate distribution & supply licenses for the area, respectively. Incumbent distribution licensee may retain the supply license to function as provider of last resort till new supply licensees step in. Distribution license may be issued for a longer duration of 25 years whereas supply license be issued for a shorter duration of 3-5 years only, both having Universal Service Obligations & Standards of Performance. To reduce regulatory discretion, a provision of deemed licensing may be introduced for supply licensees provided they fulfil the norms on Capital Adequacy, Credit worthiness and Code of Conduct rules.

Allocation of Power from existing PPAs- This is necessary to ensure continued servicing of legacy PPAs of incumbent discom. While it will initially limit the supply licensees ability to source cheaper power to offer best price for their consumers but is essential in national interest so that these economic assets remain useful till their lifetime and do not become NPAs. The Intermediary company should service existing PPA obligations through the revenue stream generated by supply licensees/re-sale of power through exchanges etc. It will analysis & compute year-wise weighted average power purchase cost or APPC as per prevalent laws (MoD, RPO, must-run, coal availability, demand etc.) and, will allocate weighted average fixed charges (for all existing contracted capacities) and weighted average of energy charges to incumbent supply licensee.

All supply licensees should procure power only from the intermediary company’s PPA portfolio in proportion of their contracted capacity till these PPAs are either exhausted or expire overtime. On exhaustion or expiry of Intermediary Company PPAs, supply licensees shall be free to procure power from sources of their choice.

Distribution & Supply Tariffs: The success of whole scheme of things will hinge upon how retail tariffs evolve overtime. Unless there are long term benefits to the consumers in terms of price, reliability, quality & value-added services etc, the reforms are not likely to be have consumer’s acceptability. Therefore, design of distribution network access charges/fixed charges for the distribution licensee needs to be regulated keeping in view the growth in load & consumers, meeting quality & performance of standards, and distribution losses. Only normative technical losses for distribution should be allowed for the distribution network. Similarly, no commercial losses (Billing & Collection related) be allowed for the supply licensees by SERCs while fixing the retail supply ceiling, albeit nominal bad debt provision may be considered.

Input cost of power for the supply licensee should be based on weighted average power purchase cost from the Intermediary company plus network access charges, wheeling charges & distribution losses. To promote competition, only a ceiling tariff be provided by the regulator for the supply licensees of an area. Within that ceiling, the supply licensee can provide various incentives, TOD etc. by improving its operational efficiency and reduction in its ROE/profit. All billing & metering at retail level to be done by supply licensee including installation of new meters by supply licensee based on consumers choice (plain vanilla or Time of Day etc). Any subsidy from government should go as DBT directly to the consumer’s account. A portability framework needs to be developed by the regulators so that consumers have a choice to switch from one supply licensee to another (only after a minimum lock in period)

If implemented diligently, unbundling & introduction of separate C&C business in power distribution sector will bring in benefits of competition and choice to the retail consumers. However, all associated risks and challenges needs to be appropriately mitigated by the government, the legislature, and the regulators so that benefits of reform are win-win for all.

 

 

About the Author:

Raj Pratap Singh retired from IAS has worked at senior positions at Central & State Government including PMO and World Bank. Presently he is Chairman of UP Electricity Regulatory Commission.

Disclaimer: Views expressed in this article are author’s opinion and does not reflect any official position

 

Draft Rules on Change in Law & Must Run Status & its implications

 

For speedy resolutions of change in Law issues pending between Generating Companies (Gencos) and the Distribution Companies (Discoms), a draft rule has been notified on Change in Law & Must Run Status. The objectives of the draft rules are righteous, and an attempt has been made to bring in clarity and uniformity across the country. This will also help the government in expediting revenue collection. Afterall, Government of India is the ultimate beneficiary of most of the change in law cases; be it imposition of increase in royalty or imposition of DMF /NMET charges on mined coal, imposition of clean energy (coal) cess, increase in railway freight or changes in taxes like GST & custom duty etc. These change in law items ultimately add to the cost of power and make electricity expensive.

The change in law event has been fairly defined  in the draft rule by incorporating all relevant provisions used in any standard PPA and various orders of the courts pronounced so far , however, there are few serious issues which may arise in implementation of these rules if  they are notified in its current form. Further, It will be very interesting to see how this rule on “Change in law” will be implemented itself as a change in law event.

There appears to be no problem If the change in law is relating only to increase in taxes and duties, because once such change in law event is notified, the generating companies has to claims the bills from the effective date of notification of the law and the procurer or discoms has to pays the dues. Final adjustments are carried out in the true-up of audited accounts. If there are disputes, the regulator decides the matter.

But the situation will be different for other change in law cases especially those relating to environmental laws. An important issue in this regard will be that of prospectivity vs retrospectivity. While the rules will apply prospectively, it is not clear whether its applicability will be only on future change in law events or all including those which have been notified prior to the notification of rules? Further, whether it will apply only on prospective biddings / tariff determination cases or on all cases including the past ones? The draft rule language appears to be nuanced with the intention to apply on all past cases of change in laws also including those notified prior to notification of the proposed rule. This can be seen from the language of Rule 2(b) read with Rule 3(e) having provision of “come into effect automatically after 30 days of the change is law event”.

“Rule-2(b) “Change in Law” means the occurrence of any of the following events after the date of submission of bids in case of tariff based bidding under Section 63 of the Act or after the determination of tariff by the Appropriate Commission under Section 62 of the Act.”

“Rule 3(b) The pass through will happen in an expeditious manner within a maximum of 30 days of the Change in Law event. “

“Rule 3(e) The pass through according to the formula stipulated above shall be calculated and shall come into effect automatically after 30 days of the Change in Law event. “

A summary table highlights the consequences of these rules.

Rule 3(b) & 3(e) applicability	On Change in laws	On PPA’s
Prospective	No Problem	No Problem
Retrospective	Problem	Problem

 Retrospective applicability of rule 3(b) & 3 (e ) will change the balance of equity in favour of the Gencos by absolving them from their responsibility of claiming the prudent additional capitalization cost only after complying  the change in law to that of deemed entitlement within 30 days of event.  Over and above, they will be rewarded with the benefits of carrying cost for the period of non-compliance. For example, if a tariff has been determined or discovered in 2015 and the change in law event, say that of installation of FGD occurred in 2018 which was complied by generating company in 2020 and the expenditure was claimed & allowed in 2020, the Genco still will be entitled for the carrying cost for the period 2018 during which it remained non-complied. This provision will out rightly favours the generating companies and put unfair & unjust burden on discom and consumers.

Presently, the cases of change in environmental laws are examined in context of difference between the applicability of existing standards and new standards on the plant & PPA .Further, compliance of change in environmental laws involves additional capital investment and operating costs which cannot be normative and must be computed on actual basis because every plant has different operating parameters and environmental clearance conditions; and are subjected to transparent process & prudence check. For example-

                                                                Emission Rules notified by MoEF & CC

Date of COD of Thermal Plant	Particulate Matters (PM) in mg/Nm3	SO2 (mg/Nm3)	NOx (mg/Nm3)	Mercury (g/Nm3)
Before 31.12.2003	100	600 for < 500 MW 200 for >500 MW	600	.03 for >500 MW
After 1.1.2004 & before 31.12.2016	50	300	300	.03
On or after 1.12017	30	100	100	.03

 It is evidently clear from above table that the change in law cases are to be applied differently on power plants with different capacity and different COD dates.

Further, the rule, being senior in hierarchy to the regulations and the PPAs, will supercede the existing mechanisms of compliance. Though legally, retrospectivity may not sustain, but will cause multiple litigations & delays before ultimately it is conclusively settled by the Supreme Court.

Another interesting part is relating to the formula given in Annexure-I for calculating the impact of change in law event. This formula is for only non-recurring cost and RE power whereas, in practice, thermal power plants are more affected because of their legacy issues. Also, the impact on change in law may be on both, recurring and non-recurring cost of the plant e.g. FGD equipment’s need more water and power which are met through increased auxiliary consumption by burning more coal and thereby increasing its O&M cost.

The part of the rule relating to the Must Run plants appears be fine except that it adds “all other Renewable Energy Plants”. While there are no issues with Solar , wind or Hydro power plants as must run, but other RE plants like bagasse based plants, which are not intermittent and use baggage as fuel, should not be given status of must run because unlike solar/hydro or wind, bagasse can be stored. Therefore, there appears no ground to include them in the must run list.

Also, the charges payable to the must run RE plants for their curtailment on grid security reasons should be borne by ancillary services mechanism and not the discoms, because it is the system operator (SLDC/RLDC) which decided curtailment on grid security and not discoms. It is expected that Ministry of Power will address these deficiencies/ issues in their final notification.

 

 

About the Author:

Raj Pratap Singh retired from IAS has worked at senior positions at Central & State Government including PMO and World Bank. Presently he is Chairman of UP Electricity Regulatory Commission.

Disclaimer: Views expressed in this article are author’s opinion and does not reflect any official position

 

Privatization of Discoms: The SBD & Challenges ahead

The financial health of discoms is deteriorating day by day and they are finding it increasingly difficult to sustain their day to day operations and debt service obligations. Realizing that distribution sector reforms are urgently needed, a draft of SBD on privatization of discoms has been circulated with disclaimer that “it do not represents the views of the Ministry and being presented with aims of initiating discussions…”. This draft SBD while brings some clarity on the subject but also raises some serious questions on the way forward. At the best it can be described as a Work in Progress of a Consultant.

Some of the welcome key features of the SBD include

a)       privatization of discom will be of the licensee (as a company as entity) and not in parts. This is a welcome step which will ensure that there is no cherry picking by private investors. Private discoms have so far only confined themselves mostly to the urban areas where the paying consumers reside, and the subsidy burden of rural areas are still borne by the respective states.

b)      The interests of existing employees are to be protected.

c)       Successor entity will have a clean balance sheet and all the past dues including true-up of accounts will be a pass through.

d)      The net asset value on which the transfer will take place, will be decided by the appropriate commission.

e)      Existing PPA’s of discoms will be transferred to the successor or successor may sign only the Bulk Supply agreement.

f)        Besides 100% equity transfer, the SBD also proposes majority sale of equity in which 74% will be transferred (with management) and remaining 26% will be retained by the state government.

Having said that there are some major challenges which needs to be addressed before moving forward:

The biggest challenge will be how the existing power purchase agreements (PPAs) of the discoms are to be allocated to the successor? At present, the discoms have a portfolio of PPAs of comprising of various fuel sources like thermal, hydel, renewable etc and of different ages procured over period. This makes the power purchase costs of each PPA different, some are low cost due to depreciated plant value and the new ones are expensive. Further, all the govt. discoms have contracted PPAs far in excess of their average demand-load and are paying stranded capacity charges to generating companies even when they are not buying power from them. For example, in UP, the average load of all discoms is around 14000 MW but the total PPA signed by them is around 26000 MW. Similarly, the total installed capacity in the country is around 375GW whereas peak load has never exceeded 185GW. Therefore, methodology for allocation of existing PPAs to successor will play a critical role in privatization- whether successor will have to take-over all existing PPAs of discom or only some of these PPAs. If only part of the PPA portfolio is taken over, which PPAs- the lower costs ones or higher cost one or at a weighted average cost?. If all existing PPAs are not taken by the successor, the successor will have windfall gains at current tariff because the present tariff comprises of total power purchase cost including the stranded capacity for the discom. Besides, how the unallocated PPAs will be serviced by the discom after transfer of assets? Same will be the case for the Bulk Supply of power to the successor. Therefore, a greater clarity is needed on this point.

Another point is arising out of mentioning of sec.131 of the Electricity Act. In the RFP (2.2.1) of SBD relating to notification of transfer scheme. Sec. 131 of the Act provides for vesting of assets from SEBs to the State government and re-vesting to state govt. companies or other companies. Now when almost all the state governments have already re-vested the assets of erstwhile SEBs to the state discoms (company), how the state government can again invoke this provision and re-vest the assets again? Now it is a case of asset transfer under the Companies Act and not sec.131 of the Electricity Act.

RFP (2.2.9(a)) relating to incentive on collection of past arrears are confusing. It may cause disputes as most of the outstanding shown in the discoms account are bogus and billed to show reduction is losses. After using reduction in losses as a bidding parameter besides equity, asking the successor to pass on the collection will cause complications and needs clarity. Similarly, mentioning additional incentive over and above Return on Equity is vague. In any case, collection of dues is not related to Return on Equity and the latter is subject to the regulations. If the intention is to supercede the regulation and treat it as a case under sec.63 of the electricity Act, the bidding must be done on the tariff and not on equity & loss reduction because only under sec.63 the tariff discovered is adopted and not regulated by the commissions.

The most confusing part is the evaluation the financial proposal dealt in 6.3 of the RFP/SBD. It talks about either highest financial quote (premium on equity) or highest cumulative reduction in ATC losses as bid parameter. While premium on equity is a tangible consideration, how only commitment on cumulative loss reduction will be the basis of asset transfer?  Any bidder can quote any figure and may not achieve that commitment. Everyone knows the fate of such commitments given by the state discoms in the past under various Financial Restructure Plans or even much publicized UDAY scheme.

An important legal aspect completely missed out in the transaction process outlined by SBD is that of obtaining prior approval of the appropriate commission under sec-17(3)  of the Electricity Act which provides for prior approval of the commission before sale, lease , exchange etc. Avoiding this will make the whole process illegal.

Since the SBD does not have the approval of Ministry so far, one believes that the points raised above will be appropriately addressed when the final SBD is notified.

 

About the Author:

Raj Pratap Singh retired from IAS has worked at senior positions at Central & State Government including PMO and World Bank. Presently he is Chairman of UP Electricity Regulatory Commission.

Disclaimer: Views expressed in this article are author’s opinion and does not reflect any official position.

Making electricity affordable in India

Impact of power sector has to be measured in terms of 5 ‘A’s- Awareness, Accessibility, Availability, Affordability and Acceptability. Recent policy measures of the government have remarkably improved the first 3’A’s i.e. awareness, accessibility and availability of power especially after launching of “Saubhagya” scheme. However, it has also brought unintended outcomes for the distribution companies whose cost of supply has increased due to increase in LT distribution network length necessitating more conductors, meters and transformers etc. Most of the newly added consumers are from rural areas of low income states like UP & Bihar and belong to subsidized categories of consumers like agriculture and rural domestic. These all have also added to the subsidy burden of respective state governments.

There is a limit to which the states can meet their subsidy obligations for its low income consumers. The state’s capacity to service power subsidy of its BPL consumers is dependent on its per capita income which varies from state to state. For example, the capacity of Delhi state government to meet its obligations and expenditures from current per capita income of Rs. 3.89 Lacs and tax to GSDP ratio of 10% will be around Rs.38, 900 per person whereas for a state like UP with per capita income of Rs.70, 500 and tax to GSDP of 10% , it will be meager Rs.7050 per person. Needless to mention that the competing demand for developmental funds from its own revenue resources in these low income states is very high and also the fact that no subsidy is provided by the central government for this purpose. Therefore making electricity affordable for its consumers becomes a priority for the sector. Lower tariffs will increase the capacity and willingness of the consumers to pay for their electricity consumptions thereby improving the financial health of discoms; it will also make the industries more competitive. Limiting focus only on reduction in cross-subsidy burden of the industries, a zero Sum game approach, may not be fruitful. In order to make it a win-win situation, the overall cost of supply must come down to make electricity affordable so that it is within capacity & willingness of increased number of consumers; reduces the cross-subsidy burden on industries; and also reduces the subsidy burden of the state governments thereby freeing fiscal space for its developmental expenditure.

The possible policy steps to make electricity affordable are as follows:

1.      Expedite overdue distribution reforms

While Generation and Transmission sectors have been unbundled, unbundling (segregation of carrier and content business) of distribution has been a non-starter. Privatization and governance reforms of distribution companies are likely to unlock huge value and provide efficiency gains through loss reduction for making power affordable. However, this option is most difficult in our political-economy as it requires wider consultations, ground preparations and strategy for managing transition to avoid disruptions during interregnum.

2.      Capping of Stranded Capacity charges

As of now, we have surplus installed capacity of around 370 GW against peak demand of 183 GW, therefore any fresh capacity addition should be limited to projected load demand growth and replacement of retiring power plants. This will reduce the stranded capacity charges the discoms are currently paying to the generating companies for their long term power purchase agreements without taking any power from them under availability based tariff regime.

3.      Say Goodbye to Cost Plus regime

a)      No new project (except Hydro and Nuclear) should be allowed on cost plus route or MoU route under section 62 of the Electricity Act. This section of the Act is reminiscent of “Enron” and had relevance only when India was power deficit. Now when country has sufficient installed capacity, it makes no sense to provide a risk free 15.5% tax free (or 22% after Tax) return on equity to the power companies. Therefore, all new generating projects including RE should compulsorily be taken up only on tariff based competitive bidding (TBCB) route and evaluated at procuring state’s periphery including inter-state transmission charges to bring in transparency.

b)      Existing power projects of CPSU’s like NTPC / PGCIL /NHPC and state power generating, transmission and distribution companies are the main beneficiary of cost plus power procurement under section-62. CERC regulations have been providing a tax free Return of Equity of 15.5% which is followed by the State Regulatory Commissions for the state’s PSUs as per statute.

c)      On the other hand, none of the major diversified unregulated private power companies could achieve higher ROE than regulated PSUs. For example in the years 15-16, 16-17, 17-18 & 18-19 , ROE of Tata Power was only 4.82%,-1.06%, 7.73% and 7.45% and ROE of CESC was 6.08%, 8.45%, 7.19% and 9.73% in respective years. Similarly ROE of all other private unregulated power companies was lower as compared to regulated PSUs.

This needs to be reviewed by linking ROE with a formula based on RBI repo rate and appropriate risk beta weightage. If we use Capital Asset Pricing Model (CAPM)-

              Return on Equity= 

              Risk Free Return+ Beta x (Market Return – Risk Free Return)

                      Risk Free Return = Average of Last 5 Years G-Sec Yield = 7.01%

                     Beta of BSE Power Index=1.004

                     Avg. Annual  Return of BSE in last 5 years (2014 to 2019)=10%

                     ROE= 7.01+ 1.004*(10-7.2) =9.82%

In present context, around 5% reduction in ROE will provide noticeable reduction in tariff. Also bringing PSUs under competitive bidding route will bring level playing field and help in tariff reduction through increased competition and efficiency gains.

1.     Restructure normative debt: equity financing to 80:20

Presently, the regulatory norm used for tariff computation of projects is 70:30 debt: equity. While debt servicing is limited only to term of the loan up-to 12 years, but RoE is allowed in perpetuity even after plant is fully depreciated. This needs to be limited to useful life of the unit. Further, If debt: equity is increased to 80:20 as in case of other infrastructure projects, the levelized tariff will be reduced due to the fact that cost of equity is higher than debt..

2.      No double whammy for consumers

National Clean Energy Fund was created as a non-lapsable fund in 2010 for promoting clean technology and since then around One Lac Crore has been collected from coal cess. However, most of it has been diverted and used for other purposes like funding to states for their GST losses etc. Asking Generating companies to install FGD and pass on the cost to the consumer amounts to double whammy for the consumers who first pay for the coal-cess and now will have to bear the FGD cost also. We should stop using cess as Tax and NCEF should be used to fund the clean energy initiative and FGD installation etc.

 

 

 

 

About the Author:

Raj Pratap Singh retired from IAS has worked at senior positions at Central & State Government including PMO and World Bank. Presently he is Chairman of UP Electricity Regulatory Commission.

Disclaimer: Views expressed in this article are author’s personal opinion.

 

Revisiting National Renewable Energy Policy

Revisiting National Renewable Energy Policy

Renewable energy (RE) is an important element of India’s energy security system. Under, Intended Nationally Determined Contribution (INDC), India plans to reduce its emissions intensity by 33 - 35% between 2005 and 2030. To this effect, it is focusing on accelerating the use of clean and renewable energy by 40% by 2030. To say something tangential to the national RE policy during current Covid & Galwan period, requires courage and conviction unless it is based on facts and figures.

The central government notified a Renewable Power Obligation (RPO) in 2011 which mandated obligated entities (primarily power distribution companies) to purchase not less than 5% of its total annual consumption of energy from renewable energy till 2015-16. In 2018, this RPO target has been enhanced to 21% to be achieved by 2022. As a consequence, the share of grid integrated RE, primarily Wind and Solar, have been increasing at a rapid rate. The present share of RE Sources is 87GW (23%) in total installed capacity of 370GW. This includes 37.7GW (10.1%) of wind and 32.3GW (8.7%) of solar energy. In 2015, the total installed capacity was around 275 GW which included 23 GW (8.3%) wind & 3.8GW (1.3%) of Solar. Besides environmental benefits, the lower cost of generation makes it a preferred source for the policy makers. While there is no denying that there are many benefits associated with RE sources and India should continue to endeavour to reach its INDC, nevertheless while doing so, one must also keep in mind the associated cost of present full throttle “one size fits all” RE Policy on the consumers and the economy. This is especially valid as India has now surplus power generation capacity.

Wind and Solar generation, unlike the conventional sources, are less predictable, intermittent in nature and are location specific but still have “must run “status over conventional sources of power. The financial Impact of Integration of Renewable Energy Sources (IRES) is more complex requiring the grid side dynamic management with economics of Renewable Energy Sources (RES). Prices of renewals have also come down significantly in recent years where average Solar & Wind prices are hovering around Rs. 3 per unit with around 10% variance depending upon geographical & techno-commercial factors. On face of it, RE prices appear to be cheaper than other contemporary conventional power plants. But there is another perspective, that of RE grid integration cost, which is not widely discussed. If we glance at the country’s Power/Energy Demand-Supply positions (compiled from data from Ministry of Power and MNRE Websites), it becomes clear that this growth in RE power is taking place at the cost of existing conventional power plants.

Power Demand-Supply Scenario

Item	2015-16	2019-20	Avg. Annual Increase (%)
Peak Demand (GW)	153	182.5	3.85%
Total Energy Generation (BU)	1107	1252	2.6%
Avg. PLF (Thermal-%)	62.3	56	-2.2%
Energy Requirement (BU)	1114	1290	3.16%
RE Generation (BU)/Share in Total Energy Generation (%)	32.8 BU / (2.96%)	114.4 BU / (9.13%)	49.75%
RE Share (%)	2.96	9.13	41.68%

Followings are some of the unintended collaterals of RE grid integration:

•      Additional energy availability from generation of Solar & Wind exceeds the growth in energy demand thereby is causing backing down of conventional power plants to accommodate “Must Run” RE.  As we are adding more and more RE Sources, average Plant Load Factor (PLF) of Thermal Power Plants is reducing. Currently, the avg. PLF of thermal PPs is hovering around technical minimum of 55% whereas around 10 years ago, it was a healthy 75%.

•      While cost of RE generation appears to be less than thermal as discovered in tariff based competitive biddings, the associated balancing costs in form of higher transmission charges (due to lower utilization of green corridors etc.)  has been camouflaged by exempting inter-state transmission charge on RE and loading it on others.

•      Discoms continue to pay for the fixed charges to the gencos for the stranded thermal capacity caused due to backing down because of their long-term capacity contracts or PPAs.

•      Average Power Purchase Cost (APPC) and Average cost of supply (ACoS) are increasing and adversely affecting the affordability of consumers to pay for expensive power. This in turn is increasing the financial stress of discoms and contagion is being passed on through defaults by Discoms to Gencos and thereafter to the banks NPAs & economy.

Costs involved in the IRES into the existing grids depend on the factors like variability of RES, lesser predictability & difficult forecasting of RES and location specific costs and subsidy costs. A broad classification of the various costs involved with the IRES into the grid are addressed in National Electricity Plan (NEP- 2018) published by Central Electricity Authority (CEA).  They include (a) Grid connection and up-gradation costs incurred on to the grid infrastructure that needs to be in place in order to integrate the RES , (b) Grid connection costs for setting up the new transmission/distribution infrastructure for the evacuation of the RES generation, (c) System operation costs which is a combination of (i) System profile costs caused due to intermittent nature of the RES  during which the thermal power plants need to back up the RES during their unavailability, (ii) Short term system balancing because  RES are variable in nature, there must be adequate storage capacity from the conventional plants and (d) Higher reserve capacity for up and down regulation is required with increasing share of RES into the generation mix and Higher variations in the RES generation during the day also requires more frequent plant/unit start-up and shut-downs for conventional plants which increases the operating costs.

A recent study by the CEA has estimated the additional costs of the RES generation for the scenario of FY 2021-22 was estimated to be Rs. 1.11 /kWh (spread over the RES generation) as per the following table:

SN	System Operation Cost	Rs/Kwh
1	Total balancing charge for gas-based station (fixed +fuel charge)	.04
2	Impact of DSM per unit	.30
3	Stand by charge (fixed costs for generating capacity for balancing intermittent RE generation, assuming 10% of maximum RE generation in MW)	.5
4	Extra transmission charge	.26
5	Total Impact (Spread Over RE Generation)	1.11

Besides these costs, there is an element of Stranded Capacity Charges which is not widely discussed. Almost all the conventional power plants (except the merchant plants) have long term PPAs tied up with procurers (discoms) based on availability based tariff regime meaning that if the plant is available, the procurer has to pay for the fixed charges (interest, depreciation, Return on Equity, O&M etc.) irrespective of scheduling of the plant and if the plant is scheduled to supply energy by the Load Despatch Centre, the procurer has to also pay for the energy charges or the variable costs like fuel costs etc. With higher grid integration of RE, the PLF of conventional thermal plants has gone down from 75% in 2011 to 56% in 2019-20. Most of the thermal plants are now operating at the technical minimum of 55% below which the O&M cost increases and life of the plant is adversely affected. Since procurer or the discoms have contacted long term PPAs prior to RPO regime with conventional plants and now also have to buy RE power under RPO regime, it is double whammy for them. They are forced to pay for the fixed capacity charges to the conventional power plants despite not buying energy from them. These stranded capacity charges , in turn, are passed on to the consumers as regulated expenditure. This is the main reason why the APPC, ACoS and the retail consumer tariffs are continuing to increase despite falling cost of renewable generation.

The financial impact of stranded capacity charges are an eye-opener. Capacity Utilization Factor (CUF) of the RES is typically low compared to that of the conventional sources, around 18-20% for Solar and 32-35% for wind energy sources. While the total installed capacity of country is 370 GW, the peak load has never exceeded 185GW. This means that rest of capacity is not put in economic use and is sunk cost. Assuming Plant Capacity Utilization Factor (CUF) for solar to be 20%, 32.2GW of added solar capacity has stranded around 6.44 GW of thermal PP capacity. Assuming Rs.7 Crore per MW as capital cost, Rs. 45080 Crore of investment in conventional Power Plants is stranded due to addition of 32.2GW of solar capacity.  Similarly, 37.7GW of wind energy at CUF of 35% has replaced 13.2 GW of conventional power plant causing stranded investment of Rs. 92,360 Crore. Thus total stranded investment due to Solar & Wind capacity additions so far is around Rs. 1,37,450 Crores which is contributing to the fiscal stress of the discoms and in turn NPAs of the Banks. Imagine the level of financial stress & NPAs in 2030 when the RE Share rises to 40% from around 9% at present.

Yearly cost of such stranding would be around Rs 17,524 Crores (amortization of the stranded cost of Rs.1, 37,450 Crores over 25 years of plant life @12% interest) which translates to around Rs 1.05 per kWh (spread over generation life of the power plant). As such, overall additional cost would be Rs. 1.05 per kWh over and above the CEA’s working of Rs 1.11 per kWh (spread over renewable generation) making total spread of around Rs. 2.16 per KWh.  This makes the effective cost of grid integrated RE as Rs. 3.0+ Rs.2.15 = Rs. 5.15 which is higher than APPC of the distribution companies. Currently, CERC has notified APPC at Rs.3.6 per Kwh (excluding Transmissions Charges). If total transmissions charges are assumed as Rs.0.75 per Kwh, the energy cost still will be only Rs.4.35 per Kwh for the conventional power. Even after taking into account likely FGD cost of around Rs.0.4-Rs.0.5 per kwh, it is still likely to be cheaper. Therefore, the need of revisiting RE policy is urgent and genuine.

Going forward, Government of India should adopt its original UNFCC stance of environment as a “Shared Concern with differentiated responsibility” for the states also and revisit the RE policy to change it from the existing “one size fits all” approach.  Logic of “One Country-One Policy” makes sense for political, social or legal matters but not is economic matter; otherwise “One Nation-One Income” will also become an agenda besides power being a concurrent subject in Indian Constitution. Best way forward for the states is to have their own respective RE absorption trajectory depending upon their socio-economic conditions , per-capita income, Tax to GDP ratio, load profiles & capacity & willingness of the consumers to pay, availability of RE sources etc., so that RPO does not become a prohibitive & unintended Green Tax on consumers specially of low income states. Also, addition of Renewables (Solar & Wind) should be limited to the replacement of the retiring thermal or Rankin cycle power plants; and to meet the future growth in energy demand so that economy could sustain the RE integration. Further, at least 10-15% of RE capacity should be coupled with storage systems to provide RTC (round the clock power) for meeting the peak demand.

If the government timely recalibrates it’s RE Policy, the damage to the financial viability of Power Sector would be repaired and harmonise with current economic mood of the nation and foreign policy post Galwan. This will be a win-win for economy, environment & politics.

About the Author:

Raj Pratap Singh retired from IAS has worked at senior positions at Central & State Government including PMO and World Bank. Presently he is Chairman of UP Electricity Regulatory Commission.

Disclaimer: Views expressed in this article are author’s personal opinion.