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Competitive landscape remains missing!

If the bottled water you buy turns out to be adulterated, you can claim compensation. Can you do the same for electricity supply in Pakistan?

Several pieces we have written before highlighted the importance of introducing competition, especially in the electricity and infrastructure sector in Pakistan. Why then after continuous reforms agenda in the power sector, very little has been achieved? Why after so much of efforts, tariffs have only gone up, performance standards have remained deficient and tiers of debt have only piled up.

We have long argued a simple idea; our sector remains deficient of adequate competition.

Let’s analyze the competitive landscape for a moment. The NEPRA Act amendment 2018 has in principle opened up the market for multiple buyer and multiple seller scenario. However, on the ground, no concrete progress has been achieved with exclusive territory operations being continued by all DISCOs and K-Electric. The current structure implies that no other player can threaten the existence of incumbents. No innovation and no challenge can be meted out by new players. As long as the existing entities adhere to minimum prescribed performance standards, the players can continue to enjoy and maintain the status quo.

This monopoly of state utilities has, in fact, been the most significant reason that has constrained the growth of power sector in Pakistan. The incumbents have prevented any meaningful reforms and efforts to attract private sector investments have yielded little results. Of the total power produced, around 20 percent continues to vanish in transmission and distribution losses with some DISCOs such as SEPCO, PESCO and HESCO recording up to 40% T&D losses annually. Much of this is plain theft. When debt piles up and payables become due, the only result is the raising of consumer end tariffs. In the previous decade only, consumer tariffs have, on average, gone up by 300%, with levying of multiple surcharges. The result is not enhanced customer service, higher efficiencies or improved financial position of DISCOs but instead marginal improvements in T&D losses, meagre service efficiencies, and a large circular debt.

With higher consumer end tariffs, presence of ubiquitous subsidy regime, and little competition from outside, this also means a strong vested interest that oppose competitive reforms. This along with uneconomic tariffs given to residential and agriculture sector compounds the problems of increasing the debt pile up. In the absence of a credible market, the power utilities only represent a ‘single-buyer model’, which means that producers of power can only sell to these state utilities. Since most of the utilities / DISCOs are virtually bankrupt, private sector investments have stayed away. Even when they have come, they have been mobilized on the back of large sovereign guarantees with high repercussions on fiscal deficit and ballooning capacity payments. As a result, much of the capacity addition has taken place with bankrupt utilities as the only off-taker. Be it public or private sector investment in generation, higher inefficiencies and inability to make timely payments have only implied a large loss levels to the tune of Rs. 120-150 billion per annum for DISCOs.

What about the unbundling of DISCOs that promised improved efficiencies? Well, the sector comprises of ten unbundled DISCOs along with GENCOs and TRANSCO. However, with a single buyer model, they have perpetuated an industry structure that is based on interconnecting chain of monopolies that nullifies the basic purpose of unbundling, which is to introduce competition. As a result, unbundling has failed to produce the expected outcomes. Instead of managing one natural monopoly, we now have ten natural monopolies at hand, all inefficient and causing perpetual drain on public resources. The alternate answer is privatization. But privatization may just translate public monopolies into private monopolies. Granted, the capital structure will become efficient with the desire to improve performance by the private sector. But will that translate into lower consumer end tariffs and improved service delivery is anybody’s guess. There have also been instances globally where private monopolies in power and water have not proportionately resulted in efficiencies that consumers have been looking for – in fact just the opposite had happened.

It is time that any meaningful reform agenda talks about competition. The old, arcane and outdated reform agenda has given little to the sector and arguably nothing to the end consumer. The gimmicks of making ‘plans’ and ‘reports’ should end. The sector needs competitive structure, and without it, nothing significant will happen.

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Sustainable development of power system

Planning of power system in the past has been dominated by the urgent need to address the large amount of load shedding. This resulted in greater attention to increasing power generation capacity while the development of T&D infrastructure lagged behind. Financial viability of the power sector has also been a matter of serious concern in the wake of likely procurement of more than needed capacity in the short run, determination of tariffs on cost plus basis in most cases, large amounts of arrears and circular debt, need to rationalize electricity retail tariff, growing dependence on imported fuels and declining share of clean energy in the generation mix. To avoid the problems caused by repeated cycles of power shortages and surpluses and mismatches in the development of various components of supply chain affecting the socio-economic development of the country, sustainable development of power system will be pursued in future through integrated planning for optimal[1], affordable and secure development of the power sector.

Integrated Planning of Power system

The integrated plan will be based on the following principles:

  1. A thorough assessment of demand and supply position taking into account Demand Side Management (DSM)[2], provision of adequate amount of reserves for scheduled shut downs of plants for maintenance, real time fluctuations in demand supply balance (spinning reserves), Forced Outages due to unforeseen failures and resource variability (Renewable Energy and Hydropower).
  2. Synchronized development of generation, transmission, distribution infrastructure and associated services in accordance with the requirements given in the various Codes and standards laid down by NEPRA[3].
  3. Incorporate modern technologies and management practices, needed for a well-managed, stable and reliable power system.
  4. Priority to be accorded to indigenous energy resources, particularly hydro, Renewable Energy (RE), Thar coal based projects with energy purchase prices arrived in accordance with the parameters given in Section 1.2(a) below.
  5. Meeting the demand of under/or unserved areas through systematic grid extensions, local mini-grids and off-grid applications for use of RE. 
  6. Power plan will be financially viable, affordable and integrated with the overall macroeconomic planning framework of the country

[1] (Least Cost Planning adjusted for requirements for transfer of technology, energy security and development of underserved or unserved areas).

[2] Demand Side Management (DSM) will be promoted through various measures such as time of day tariffs, demand charge for residential sector except for life line consumers, support of Energy Service Companies (ESCOs) through fiscal and financial instruments/facilities to assist the end customers in carrying out DSM. NEECA will also launch several programs to promote DSM.

[3] Commercial Code, Grid Code, etc.

Financial Viability of the Power Sector

Electricity Procurement

The government is reforming the power sector such that the price of electricity supply is determined through open access and market-based competition in the long run (see road map in Section 6 below). However, in the interim, the cost of electricity purchase by DISCOs will be minimized, to the extent possible based on the following principles:

  1. New power capacity will be acquired on the basis of estimated requirements under integrated plan to avoid shortage or idle capacity in future. The integrated plan would be updated every two years to remain in sync with actual developments. Electricity will be procured at least possible cost adjusted only for needs for energy security and development of underserved or unserved areas.
  2. Electricity from following categories of projects will be procured on the basis of international competitive bidding[1]:
    1. All new thermal, solar and wind power
    2. Hydropower and indigenous coal based power projects, where feasibility and engineering studies have been prepared.
  3. Hydropower and Indigenous coal projects on raw sites (those sites for which detailed feasibility and engineering study has not been done) will receive Letter of Intent (LOI), through international competitive bidding for the work program, to carry out feasibility studies. LOI may also be issued to IPPs for unsolicited hydropower projects for raw sites, identified by the IPP, after evaluation of the proposal by the PPIB/AEDB.
  4. LOI/LOS will be given to projects envisaging a specified minimum component of transfer of technology (TOT) on the basis of international competitive bidding with suitable incentive for maximizing TOT component.
  5. Government to Government (G-G)/ Transfer of Technology (TOT) Projects and nuclear power projects will also be eligible for supply of electricity to NTDC system (preferably through competitive bidding within the donor country). Before making the award, prevailing international prices will be used as benchmark.
  6. Tariffs for the projects developed on the basis of LOI (i.e. projects on raw sites), will be based on EPC and O&M costs arrived through competition amongst at least three bidders under the supervision of a third party. The cost of Balance of Plant (BOP) including project development costs, financing costs and ROR will also be required to be competitive. Any subcontracting of EPC/O&M will require Government of Pakistan (GOP) approval.
  7. For hydropower projects, resource variability risk will be borne by the purchaser as per the present arrangement (based on monitoring of actual water flows). Other RE projects will bear the resource risk themselves.
  8. Renewable Energy[2] (RE), hydropower, nuclear and indigenous coal projects (with back to back guarantee to miner), will be “must run” projects.
  9. Payment obligations of the federal power purchaser entities will be backed through government guarantee.
  10. LOI/LOS will be issued by AEDB/PPIB for projects feeding electricity in the national grid for purchase by Federal entities in accordance with this policy. Provinces may issue LOI/LOS according to their policies as per the Constitution.
  11. Contribution of customers towards electricity supply through net metering regime based on distributed solar power generation will be promoted through attractive tariff and financing support schemes (see Section 2.2 below).

It is also recognized that any large capacity surplus will have to be converted to economic opportunities in order to safeguard against the diseconomies and tariff impacts caused by idle capacity. For this purpose demand promotion schemes will be devised and tariff design will be improved to promote consumption in the productive sectors.

Curtailing aggregate technical and commercial (atc) losses to reduce arrears

Sustainability of the power sector is seriously threatened by accumulation of arrears due to failure in reducing the power system losses to targeted levels and less than full recovery of revenues.  These Aggregate Technical and Commercial losses (ATC) result in nonpayment to IPPs who in turn fail to make payments to primary energy/fuel supply companies. The Government recognizes the urgency of settlement of these issues. A committee of experts will be formed to make recommendations to address the root causes of ATC on permanent basis.

Rationalizing electricity tariffs

The Power Sector Reform in the country is witnessing a progressive tariff rationalization process. Tariff is based on the principle of cost recovery except for consumers with consumption below 300KWh and agricultural tube wells. In future, the thresh hold for subsidised customers will be further reduced. Simultaneous steps are being taken to gradually move towards open access and competitive market regime where the electricity prices will be market based. However, in the interim period, NEPRA shall determine the tariff in the light of the Amendment in 1997 NEPRA Act (2018). In summary, the key features will be the following:

  1. Uniform tariff for distribution licensees wholly owned and controlled by a common shareholder.
  2. Cost of service except for poor class of customers.
  3. Through pricing signals, promote energy efficiency, conservation and DSM
  4. Promote net metering.
  5. Promote use of surplus power by industries and commercial sectors[3].
  6. Tariff for off grid, mini grid customers to be subsidized.
  7. In the long run, prices be determined by the market itself.
  8. Cross subsidies will be minimized.

Tariff structure will be guided by the principle of reducing the cost of electricity through, but not limited to, efficiency in supply, improvement in end-use efficiency, improved power factors, better customer awareness and other demand management measures. For preparation and implementation of demand management programs, the National Energy Efficiency and Conservation Authority (NEECA) will be revitalized.

Priorities for investment

Emergence of power generation surplus provides an opportunity and gives fiscal space to focus on and address the long overdue need for improvement of transmission and distribution infrastructure. For this purpose, rehabilitation, augmentation and expansion of transmission and distribution system benefitting from modern technologies and management practices will get the highest priority. Financing schemes will be designed to promote investment by private sector in transmission and distribution infrastructure. The transmission and distribution companies will be also arranging resources from commercial sector, market and other means besides the conventional recourse to PSDP/Donors.  

New power generation projects will be required once the surplus power is absorbed. In this context, clean-energy and indigenous fuel-based projects will get priority. The new projects’ financing plans will be guided by the integrated long-term plans, which will allow their investment arrangements to be made reasonably up-front. However, investors will be responsible to raise financing through financial markets on the basis of strengths of projects, balance sheets, other market-based collaterals and/or innovative financing schemes except for nuclear, large hydro (run-of-river or multipurpose), technology transfer or other strategically important projects.


[1] Letter of Support (LOS) to be given to the successful bidder.

[2] RE means wind and solar based projects

[3] It may be considered that for the period during which the generation capacity is projected  to be surplus beyond the reasonable limit ( approximately up to 2023) , tariff for industrial sector be so designed that it would decline for  consumption above a minimum thresh hold for industrial and commercial customers reducing their cost of doing business.

Promotion of clean energy for power generation & environmentally sustainable development

Pakistan is heavily dependent on imported energy in the form of oil, LNG and coal.  The composition of primary energy power generation capacity shows that hydropower generation from large hydropower projects and renewable energy contribute about 25% and 4% of the total electricity generation, respectively. In terms of consumption, RE is meeting less than 3% of the total electricity consumption. Keeping in view the Sustainable Development Goals (SDG) in the wake of international climate change agenda and Pakistan’s commitment to reduce its carbon footprint, Pakistan will strongly promote the use of RE, hydropower from large projects and efficient use of energy. In this vein, the share of RE is proposed to increase to at least 10 % in 2023 and 20 % in 2030. The share of large hydropower generation will also be increased from 25 % to 35%. To achieve these objectives, following are the key elements of policy.

On-grid systems

  1. There will be no cap on the quantum of intermittent electricity to be absorbed by the NTDC/DISCOs up to 2030.
  2. NTDC and DISCOs will be required to identify RE Zones near major grid nodes and points of interconnection in consultation with Provinces.
  3. It will be mandatory for NTDC/DISCOs to provide connectivity within RE Zones and/or within a certain radius of network. All the required improvements needed in the grid system to provide connectivity, including the provision of adequate generation reserves, will be responsibility of NTDC/DISCOs. Grid interconnection will be provided 3 months in advance of commissioning date of projects to enable testing of plants. Arrangement of funds will be the responsibility of NTDC/DISCO, who may arrange it through PSDP, donors, commercial borrowing, self-financing or any other means.  IPP may have the option to provide funds for transmission line on terms to be mutually agreed.
  4. Requests for Proposals (RFPs) for new capacity on the basis of competition will envisage maximization of indigenous manufacturing component.
  5. Distributed Solar Power projects – both stand-alone type and those based on Off-Grid applications – will be promoted.
  6. Planning and construction of Large Hydro Power Plants will get priority over the fossil fuel based thermal plants.
  7. Substitution of subsidized electricity in agriculture and domestic sector with consumption below 300 KWh per month, supplied through grid, with solar based electricity generation schemes on concessional terms.
  8. Innovative financing schemes for upscaling use of RE in industry (e.g. through wheeling) and agriculture (e.g. solar tube-wells) etc. will be prepared.
  9. Wind resource assessment will be carried out for new prospective sites and collection of data for bankable projects through appropriate agencies.
  10. A database will be set up for all the new possible avenues and of the operating renewable energy projects freely accessible to general public, researchers, academia, project developers and financiers to promote evolution of new RE projects.

Distributed Solar Power

Roof-top solar projects with or without net metering will be actively promoted in residential, government, commercial and education sectors (e.g. schools).  Formation of Energy Service Companies (ESCOs) will be encouraged. For this purpose, various types of training programs will be launched to promote entrepreneurship, methods of formation and functioning of ESCOs, capacity building, preparation of sample drafts of agreements with clients etc. The initiative will be supported by enabling access to easy and subsidized sources of funds. Projects for utilization of free spaces such as parks, water reservoirs, agriculture farms, deserts and many other possible initiatives for generation and utilization of solar energy.

Clean Energy Fund and Other Sources of Funding the Clean Energy Initiative

It is proposed to set up a Clean Energy Fund through Clean Energy Levy on the revenue of all oil, gas and coal fuel marketing companies. The purpose of this levy would be to discourage use of fossil fuels emitting GHGs (Green House Gases) and provide funds for schemes/projects for promotion of clean energy, universal access of electricity using renewable energy technologies, indigenization of clean energy technologies, leverage financing of large clean energy projects, concessional funding for projects in far flung areas in the form of mini-grids, roof-top solar projects etc. The resources may also be used to eliminate perpetual subsidy to the customers consuming less than 300KWh/month by enabling them to switch over to roof-top solar energy through one time grant funding of a major share of the cost of installation. The levy may also support R&D for clean energy.

The proceeds of this levy are proposed to be kept in a separate account under a Clean Energy Fund, which will be dedicated to the objectives stated above. It is proposed to be under an independent and transparent administration created through an Act of Parliament. Detailed guidelines for the management and use of the Fund will be prepared immediately after the passage of the budget proposal. The Fund would be so structured and positioned that the domestically raised resources be the seed money for attracting larger funds from various international resources for funding promotion of clean energy and mitigating effects of climate change, grants or concessionary funding from donors and corporate sector.

Is Carbon Capture and Storage for Pakistan?

Carbon Capture and Storage (CCS) is an expensive technology proposition. By cost numbers, the levelized cost of energy is significantly higher for CCS generation as compared to other renewable energy and traditional fossil fuel generation options available. Pakistan already has an expensive energy generation mix which is heavily reliant on furnace oil and diesel generation (around 40%), which accounts for 75% of total electricity costs. Expensive electricity has made industry uncompetitive and has created social unrest. The new power policy 2013 explicitly states to lower the cost of generation and create a generation mix which is environmentally sustainable and financially viable in the long run.

In the light of an already expensive generation mix and Pakistan’s efforts to move towards cheaper options such as coal and hydel, electricity generation through CCS will not be easy to sell to policy makers and the regulator, NEPRA. Both government and the regulator are cognizant of the need to lower the cost of electricity generation to protect consumer interests and balance environmental goals. With Pakistan’s negligible emissions, the policy makers may argue that lowering the cost of electricity generation rank as more important than reducing future emissions or may be to push other renewable options available such as solar PV and wind more vigorously where the costs have already declined substantially.

Nonetheless, the scope of using CCS technology in industries (cement, fertilizer and natural gas processing) is still high where the product (captured CO2) can be sold to E&P companies who could use it to augment oil supplies through EOR. The biggest hurdle remains, however, the cost of capture equipment and hence the financing of the CCS plant which poses financial challenges to the entire deployment. To overcome financing challenges through improved R&D, demonstration CCS plants need to be built using different technologies, under several types of coal (bituminous, sub-bituminous and lignite) while occurring in different terrains and different settings.

Also, it is important to evaluate key CCS demonstration project financing transactions that have happened lately to fully evaluate the impact of policy, financial and governmental support in shaping CCS project deployment. The Global CCS Institute has presented annual lists of CCS projects in various stages of development, going from announced projects all the way to completed projects (“operate”). In the 2015 list, the GCCSI has identified a total of 22 projects in “Operate” (operational) and “Execute” (under-construction) mode, implying that these projects have achieved financial close or are currently being deployed.

Four of the 22 projects can be categorised as Pioneer CCS projects. These projects share two characteristics: (1) they were built with little or no government support and (2) they all start with a high purity CO2 source that requires only compression and transport. One trait the four projects share is that the CCS process was a small part of a larger business project and that existing business drivers played a key role in their justification (Ref: 808). The remaining nine CCS projects all relied on governmental financial support. Seven of these projects resulted from specific government programs designed to promote CCS demonstrations. Three of these plants are operating, while the other six are under construction (Ref: 808).

The reportable data goes on to suggest that CCS projects may be viable on a case to case basis but their usefulness as full-fledged technology option is still far from fruition. The global examples demonstrate that CCS applications are not fully commercially viable except where government support is available or where EOR markets are well established. The price on emissions in most markets or the return on investment has not been high enough to mobilise private sector investment. In fact, there will be many projects which will not proceed given current low emissions price, low oil prices and longer-term uncertainty around government support. Where projects have proceeded, they appear largely motivated by a value being placed on corporate social responsibility, R&D or an underlying corporate objective to demonstrate CCS for long-term, business strategy purposes (Ref: 806).

The business case for a CCS demonstration project in a developing country like Pakistan remains weak, primarily because of the lack of financial incentives to justify the “incremental” costs associated with a CCS project. The imbalance between “risk and reward” for early movers and investors remain a major impediment in making CCS project deployment a reality. Naturally, Government will have to step in to make early inroads in CCS deployment, lead the way with demonstration projects and allow incentives to take the CCS technology out from the “valley of death”.

In the last few years, Pakistan has seen growth in private and public-sector investment mobilization in infrastructure projects. CPEC has emerged as one long term sustainable mode of financing large infrastructure projects to fund emerging technology and investment needs. With China increasingly the front runner in capture equipment manufacturing, Pakistan can look forward to fund a demonstration CCS project under a collaborative funding mechanism and arrange for long tenor funds at subsidized rates. The multilateral support is another avenue which could be used to leverage investments for CCS demonstration projects. The Asian Development Bank in collaboration with other development partners such as the World Bank, the International Finance Corporation, Global Environment Facility and the United Nations Framework for Climate Change can fund CCS project financing either through risk mitigation tools, partial guarantees or loans to fund fully or part of the CCS project finance.

Naturally, the impact of CCS tariffs on electricity prices will be high – with prices rising to almost double the cost of a conventional coal plant. Nonetheless, there will be benefits associated for Pakistan in the long run for transitioning to coal. Pakistan will be in a position to leverage CCS technology, apply it in industrial or power sources and then leverage the technology for further deployment in other countries. It could also benefit from the fact that bulk of oil fields in Pakistan are on the verge of depletion and captured CO2 product can be used to augment oil supplies through EOR activities, thus saving the foreign exchange outflows and relying on indigenous oil production. Last, it can use the depleted oil and gas fields and turn them into long term CO2 storage facilities – prolonging their lives to earn decent rate of returns, which otherwise would not have been possible.

If you are interested in obtaining your financial and economic analysis of CCS study in Pakistan, get in touch with us at info@resourcesfuture.com

Financial and economic Aspects of CCS in Pakistan

A financial and economic analysis scoping study was conducted to review and assess potential for carbon dioxide (CO2) from electricity generation from coal power plant. The Resources Future (RF) study highlights indicative cost structures for greenfield projects with and without CCS, defining and quantifying the elements of CCS costs, calculating cost inputs and subsequently the results. The study further highlights review of relevant financing mechanisms, including proposed funding vehicles for CCS projects in Pakistan and opportunities for public and private sector investments in Pakistan along with calculation of expected impacts on electricity tariffs if CCS is deployed. Last, the study calculated financial and economic risk assessments of potential first of a kind CCS power plants and carry out a sensitivity analysis on key variables to assess impact on end user tariffs.

The study highlights that the cost of CO2 capture, transport and storage will vary according to the type of technologies applied and projects undertaken. In the CCS project economics, enhanced oil recovery (EOR) can play a key role towards economic viability. If the selected storage site is a hydrocarbon reservoir where EOR may be economically viable, it will create the potential to provide additional sources of income (such as the sales of additional recovered crude oil) to the project, improving financial and economic returns and lowering required level of investments for the CCS project.

It may be important to note that the capital and variable costs presented in the RF study are best estimates only. This is primarily because cost inputs such as capex and O&M figures are hard to obtain from public disclosures with specific site storages and transportation networks. The study uses NEPRA’s cost benchmarks and past determinations wherever available as a tool for forward looking technical and economic analysis. NEPRA’s determinations have been useful since it clearly spells out assumptions and benchmarks used in one off and upfront tariff determinations for coal power plants in Pakistan.

As a methodology, the analysis in this study has taken parameters available in NEPRA’s reference tariffs for conventional coal power plant and adds upon the cost of the capture equipment using the post combustion technology for Pulverized Coal plants. The costs of transport and storage is then added using assumptions that can best be estimated only subsequent to the definition and identification of the plant and storage sites location. Last, as discussed in the ROE analysis, all project scenarios have been developed using commercial benchmarks which may change subject to government funding or donor support. It may be recommended therefore that this analysis is read in conjunction with the sensitivity analysis. The sensitivity analysis attempts to ascertain range of tariffs for CCS demonstration project in Pakistan given changes in variables such as WACC, capex, O&M costs and ROE parameters and its respective impacts on LCOE, NPV and IRR. The table highlights estimate of tariffs under three different scenarios; LCOE without CCS, LCOE with capture equipment and LCOE with capture, transport and storage components. The results are highlighted in the table below.

Table: Estimated levelized tariff under different scenarios.

The RF study goes on to highlight potential pre-construction, construction and operational risk to make CCS projects a success. It also highlights potential funding mechanisms to fund a CCS project such as China Pakistan Economic Corridor, Pakistan Development Fund Limited, Governmental support and development partner’s sources to build a first of a kind CCS project in Pakistan.

If you are interested in availing the opportunity to know more about CCS potential in Pakistan, get in touch with us today to purchase your copy of CCS Pakistan copy today at info@resourcesfuture.com.

Pakistan’s Energy Sector – What we achieved in the last decade!

The 2010 energy recovery plan prepared under the Friends of Democratic Pakistan (FODP0 study, and 2013 National Power Policy objectives have partly been achieved as new generation and transmission facilities were either launched or completed. Imported and local coal-based power generation capacity has been added or will be added in the next two years (FY19 and FY20), thereby addressing both the capacity shortages and the power mix issues to a large extent. Power system losses have gone down to about 18% and revenue recoveries have increased to about 94%. Failures include: regression on regulatory issues; lack of integrated power system planning; recoveries issue has not been completely solved although better numbers have been achieved by imposition of surcharges which has brought down the magnitude of cross subsidy. Industrial cross subsidy to domestic sector (high industrial tariffs) has impacted on export competitiveness of the industries and a mechanism to settle the inter-DISCO cross subsidy is yet to be devised.

 

Progress on hydropower has been less than desired as major hydro powers viz. Dasu and Diamer-Bhasha have not yet entered the construction phase. On positive side, Neelum Jhelum HPP and Tarbela extension are nearing completion and a number of high head medium/small output plants have achieved their CODs. Dependence on foreign fuels persists adding to the growing imbalance of trade and foreign exchange reserves problems. Privatization and restructuring issues have received attention, courtesy IMF Program (since concluded), but has seen little progress. Privatization of the four high-performing DISCOs is deemed to be crucial since the proceeds will write off the circular debt parked in the Power Holding Company. Market reform and regulation issues also received little attention, and in some ways regulatory affairs have not progressed. Moving towards a multi buyer market structure is seen as a must for the sector to perform.

 

Pakistan’s primary energy use has seen a CAGR of 3.9% during the 6-year period between 2010 and 2015. The detailed table showing the trend of primary energy supplies and projections are given in the following table.

Pakistan’s Energy Sector – What we achieved in the last decade!

The above Table presents the steady decline of gas at a rate of about 1.4% p.a. over the period 2010 to 2017.  With international gas import projects (TAPI and IPI) seemingly stalled, Pakistan has turned to LNG to bridge the gap. LNG supplies are set to increase; this will balance the decreasing domestic gas supplies and will substitute diesel and furnace oil, mainly in the power generation sector.  Domestic coal supplies have increased, although at a very low average rate of 1.2% p.a.  The portion of imported coal in the power generation mix is set to increase in the near future as its offtake at a large scale is about to begin by the near-completion imported coal power plants. It’s expected that imported fuels, including gas and coal, will exceed 50% of the total primary energy supplies by 2018. Oil supplies have increased at an average rate of 4.3% p.a between 2010 and 2017 and half the oil supplied is through imports. The portion of imported oil as a percentage of total oil supplies has slightly decreased in 2017.

 

The Energy sector in the period 2009 to 2017 has seen some significant additions, especially, the progress since 2013 has been impressive on many counts. Some of the gas shortage has been bridged by LNG imports as the first LNG terminal is operating since 2016 and a second one is targeted for commissioning by end of 2017. Additional LNG terminals are being installed which will be owned and managed by the private sector. New LNG based power generating capacity continues to be added aggressively, thereby bridging the power gap and effectively eliminating load shedding. The power generation mix is also shifting due to addition of new coal fired power plants and LNG power plants. This is causing excessive reliance on imports which will further increase in the next five years, as imported coal based plants and LNG based combined cycle power plants will register an increase in fuel utilization and is not sustainable in the long run.

 

During recent years improvements have been registered in: electricity transmission and distribution losses (which are expected to be 17.2 % by end of 2017-18 as compared to 18.2 % in 2017); revenue recoveries (which are reported to be 96% by end of FY 2017 as compared to 94% in FY 2016). The improved performance of energy sector due to the recent building of new gas, coal and power infrastructure masks some glaring failures. The goal to rely more on indigenous energy sources is not likely to be achieved in the near future. This, in turn, is increasing dependence on imported sources of energy thus further ballooning the country’s balance of payments. Pakistan’s energy use intensity (EUI, which is a measure of Gross GDP divided by energy use) is among the highest amongst the developing countries for which energy efficiency improvement initiatives need to be launched. The governance issues of energy sector need immediate attention as they are at the root of some of the problems of the sector. In hydrocarbons, the E&P activities are virtually stagnant as some of the major companies are not finding it financially attractive to invest in Pakistan. There has been virtually no progress in exploiting the shale or off-shore petroleum resources. Mining of local coal (except in Thar coal-fields, where significant progress is being made) has not received much attention. Biogas and biomass (except bagasse) has also received little attention. Especially, biomass usage for village electrification and for tube well conversions is viable and needs to be considered. Energy efficiency and conservation are low-hanging fruit, but they are still not playing their rightful role.

 

Utility scale solar power plants, both PV based and CSP, offer a great potential for meeting Pakistan’s future energy needs. Apart from one on-going solar power project in Punjab (Quaid-e-Azam Solar Park) there are no other significant ones in the pipeline. The regulator has shifted from the earlier policy of upfront tariffs and, instead, solar sites will now be offered on the basis of competitive bidding. The result of this change in policy are yet to be seen, but in the meantime roof-top solar can be developed at a faster rate than at present with active promotion of Net-Metering program by DISCOs. One of the impediments solar roof projects are facing is the lack of standardization of solar panels available in the market for which NEECA will need to take necessary measures. Microfinance can be a useful instrument in developing both solar household projects as well as rural micro-grids. Solar water heating in industrial and domestic sector has good potential and is in need of incentives for its promotion. The regulator has withdrawn upfront tariffs for wind projects as well which too will be offered on the basis of competitive bidding from now on.

 

Some of the 2013 Power Policy objectives have been achieved and it is expected that by 2018 the new power generation plants will nearly eliminate the load shedding. While rightly focusing on arranging new investments in the power sector, the Government has underestimated the need for integrated planning of the sector. The decision makers went through a number of mid-course corrections in their planning (examples are Gadani coal projects, Nandipur project and Guddu project) which suggests that the government was moving too fast down the road to commissioning new power plants and neglecting to carry out a proper feasibility study of all the requirements before induction of larger scale power generation into the system. This calls for taking urgent steps to put the energy planning process on sound footings.

 

During the last few years transmission system has presented some problems as in many instances transmission was not in place to deliver already commissioned capacity. In some cases, transmission was unable to deliver the full capacity of a plant. The transmission system master plan does provide detailed plans, but these are apparently not implemented in the order and timeline required by the newly added generating capacity. There are also frequent changes in generation addition plans and matching changes in transmission plans are not made or implemented to adopt to these changes. Transmission requirements to deliver the additional capacity that is being added are being studied by NTDC and it’s expected that by 2020 the transmission system will be in a reasonable shape to serve peak demand.

 

The Circular Debt issue has beset the system for years. In 2015, the Government issued a policy document which aimed to limit circular debt to Rs.350 billion. This has partly been achieved, but by means of: surcharges; and changes in the regulatory regime. Losses and recoveries are showing signs of improvement in FY 2018. The inherent cross subsidization of domestic customers by industrial customers has not been addressed. This results in high industrial tariffs which has negative implications for industrial output and GDP growth.  DISCOs also do not deliver acceptable service to customers due to system efficiencies and human resource considerations. Tax issues with FBR have not been resolved by DISCOs and, likewise, tariff issues relating to FATA and AJ&K continue to linger.

 

Improvements in the decision-making process and their implementation could be an important ingredient in working toward a fair and sustainable electricity sector. Well-functioning governance system will allow for better decision making about the goals of electricity reform and ensure that these goals are modified to local needs. Better governance will allow for making and implementing decisions at the right time and ensure a means of holding all the stakeholders (government, private sector, public sector organizations and consumers) accountable for their actions. Generally speaking, the energy sector has been a victim of bad or slow decision-making due to a serious lack of institutional capacity. One key change that is needed is that policy-makers need to focus on longer term interest of the sector rather than short-term goals which will be one of the areas on which this study will be giving advice on.

 

 

State of the Energy Sector 2010 – 2016

The analysis of Pakistan’s primary energy supplies during the period 2010 to 2016 indicates that there has been a decrease in gas supplies which was compensated by increase in oil and, and to some extent, Re-gasified Liquified Natural Gas (RLNG) and coal (Table-1).  The total primary energy supplies (not including non-commercial energy) registered an CAGR of 2.6% between 2010 and 2016. A comparison of energy growth rate with the GDP growth rate – which was below 3% in 2010, above 3 % for the next three years and above 4% in the last two years – indicates a weak correlation although suppressed demand due to energy shortages can be attributed as one of the possible reasons.

State of the Energy Sector 2010 – 2016

From a comparison between 2010-2016, Pakistan witnessed oil and oil products increasing their share in the energy mix, whereas gas share in the total primary energy mix decreasing by 6.3% over the 6-year period (Annex-1). The decrease in share of gas in overall energy mix was marginally compensated due to increase in the share of Liquified Petroleum Gas (LPG), which went up from 0.42% to 0.79%, and to some extent RLNG which constituted 2.10% increase. Share of hydropower as a percent of total energy supplies was 8.26% in 2010 but went down to 7.23% in 2016. The contribution of nuclear based energy, which contributed at an increasing rate, went up from less than 1% in 2010 to more than 7% in 2016.

 

Supply shortfall of natural gas (which contributes about 50% of the commercial energy supplies) has ranged between 10% and 15% of demand in recent years. The gas consumption by the power sector in Pakistan has increased over the years and resulted in a shortfall of 1,623 mmcfd in FY 2013, rising to 3,541 mmcfd in FY 2017. The gap between supply and demand of gas has been recently bridged after the commissioning of two LNG terminals and signing of LNG import agreements

 

Energy intensity, which is a measure of the efficiency of energy use, decreased by a nominal 0.5% during the last 7 years. The industrial sector responded to depleting gas and uncertain electricity supplies by increased reliance on coal, mainly imported coal. Transport sector also registered a decrease in LPG and CNG consumption and compensated by increase in oil consumption. Residential sector registered an increase in oil, gas and electricity consumption. The self-reliance objective is not being met as the imports as percent of total energy registered an increase due to higher oil and coal imports. The efficiency target was also not met as losses in the gas and power sector increased at an average rate of 3.6% and losses in the gas and oil sector registered a growth of 5.6%.  Even when Industry and transport were denied gas supplies the residential customers registered an increase of 4.7% over the period.  Gas supplies to residential customers continued to increase despite the depleting domestic gas supplies.

 

Distribution area is the most underperforming area of the power sector. NEPRA performance evaluation report of ex-WAPDA distribution companies (DISCOs) and KE for 2015-16 makes a comparison of their performance during 4 (four) succeeding years starting 2011-12 through 2014-15.  The report states that there was no major improvement in the performance of DISCOs and KE under the Performance Standards (Distribution) Rules (PSDR) 2005. Under the said rules, each distribution company is required to submit an Annual Performance Report (APR) in the prescribed format to NEPRA. The regulator also noted that DISCOs and KE caused a loss of around PKR 49 billion and PKR 83 billion, respectively, to the national exchequer in 2015-16 due to their inefficiency with respect to transmission and dispatch (T&D) losses and recovery targets. High losses and low recoveries are also a contributing factor to the growing circular debt.

 

The recommendations in the past have been presented in a setting when the energy sector was beset with crippling issues, mainly electricity and gas shortages.  Electricity shortages which were about 6000 MWs and 10 hours a day in 2010 now stand nearly eliminated.  The investments which are already in place will ensure that by 2018 there will be, at worst, only nominal load shedding. Capacity has been added or is in the process of being added, however, hydel-based capacity additions are not at the desired level that would improve the indigenous element of total capacity. On the other hand, the overall power generation fuel mix is being rationalized and, especially, coal, RLNG, nuclear and renewable have started contributing a greater share in the power mix. Generation Companies (GENCOs) continue to underperform as both their efficiency and availability are low and they have failed to perform to acceptable standards. The expansion of primary transmission, secondary transmission and distribution networks has also been at a low rate and there are some critical bottlenecks in the system due to reduced capacity of transmission system.

 

Common Misconceptions about Renewable Energy in Pakistan

Energy crisis in Pakistan is a serious one. In cities, we face 6-8 hours of load shedding (except parts of Karachi) and in rural areas, typical load shed figure is anywhere between 12-18 hours. According to estimates, our supply numbers have been stagnated at just around average of 11,000MW for the last seven years and our demand has kept soaring and gone past well beyond an average of 18,000MW. Yet in a dire power crisis, we continue to hear misconception on renewable energy generation as compared to current fossil fuel generation status quo.

The first general misconception goes like this: Renewable energy generation is not competitive today and mainly live on governmental subsidies. Let us analyze this argument. The current status quo of thermal generation (Furnace Oil and High Speed Diesel) produces approximately 40% of total electricity generation. Since price of FO and HSD are linked to international oil prices and rupee exchange parity, we have to subsidize the end user price of electricity as Tariff Differential Subsidies (TDS) which is the difference between the actual costs of electricity and what consumers pay. In the last five years alone, the Government of Pakistan has paid TDS of PKR 1,500 billion as a difference between the actual price of electricity and price billed to consumers (since consumers can’t afford to pay for the expensive energy our system produces). This subsidy amount of Rs. 1.5 trillion is a humongous one. With this price tag, almost 30,000 new village infrastructure could have been upgraded, 24 full scale metro projects could have been completed, almost 75,000 new high end schools and hospitals could have been built, approximately 100,000 new libraries could have been constructed from ground up and almost 5,000MW of new renewable energy capacity could have been added to the national grid. Thermal energy is not cheap. And if people think renewable energy is expensive, just remember price tag of Rs. 1.5 trillion as subsidies for thermal generation in the last five years alone.

Second misconception goes like this: Cost of producing electricity from renewable energy exceeds the cost of electricity from thermal generation, hence thermal generation should be preferred. This is again a matter of perspective. Let’s suppose if we would have built our energy system based on small distributive, community driven system rather than large scale, centralized system that we currently operate in, we would not have needed sprawling costs that we incur today on thing such as large scale transmission lines, transformers, distribution grids, cables, meters, people to read meters, planners and headquarters etc. In local parlance, this cost is typically knows as Distribution Margin (DM) and is typically one fifth of the total cost of electricity today. Add to this the cost of line losses that we incur today on our centralized energy systems and power theft, which almost always causes our power system to cripple down and ask for higher subsidies resulting in massive debt problems. Even at large scale now, renewables are competing against thermal and especially coal power generation. The best wind turbine in town today is producing electricity at the same cost as large scale coal generation. Hydel power generation is so cheap that even if we tap 20% of the total hydel potential, we will require no subsidies. What renewables further provide is fuel price hedging since price of solar and wind resources have been bestowed by nature for free. Even if we install renewables at a higher price, we no longer have to worry about fuel price volatility and exploding fiscal deficits in times when price of oil balloons up. Further, the externalities such as environmental cost, health costs of producing renewable energy far outshine the cost of thermal generation.

Third misconception is something like this: Renewable energy is intermittent (only when sun is shining and wind is blowing) and thermal generation is baseload (can run 24 hours). This argument is technically true. Solar energy produces mostly during the day time but we also need most electricity during that time period only. Wind generally blows during the night time and if combined well with solar can give a powerful solution to intermittency. Hydel generation produces maximum electricity during summer time, just when we need most electricity. Technical intermittency remains an issue but we need to re-define intermittency in Pakistan’s context. The question we need to ask is have we received uninterrupted electricity supply on thermal generation? The obvious answer is a resounding no. With 18 hours of load shedding, intermittency is a problem more for thermal based generation rather than renewables. Renewables may encounter engineering or natural intermittency problem. But thermal generation produces far greater financial intermittency problems since our power sector cannot afford high furnace oil and diesel prices. Think of creeping circular debt bailouts time and again, nationwide petrol crisis and large scale black outs because somehow our power sector have not generated enough financial muscle to cater to increasing production levels at higher prices. Intermittency is a major risk for thermal generation and not for renewables.

Third misconception is something like this: Renewable energy is intermittent (only when sun is shining and wind is blowing) and thermal generation is baseload (can run 24 hours). This argument is technically true. Solar energy produces mostly during the day time but we also need most electricity during that time period only. Wind generally blows during the night time and if combined well with solar can give a powerful solution to intermittency. Hydel generation produces maximum electricity during summer time, just when we need most electricity. Technical intermittency remains an issue but we need to re-define intermittency in Pakistan’s context. The question we need to ask is have we received uninterrupted electricity supply on thermal generation? The obvious answer is a resounding no. With 18 hours of load shedding, intermittency is a problem more for thermal based generation rather than renewables. Renewables may encounter engineering or natural intermittency problem. But thermal generation produces far greater financial intermittency problems since our power sector cannot afford high furnace oil and diesel prices. Think of creeping circular debt bailouts time and again, nationwide petrol crisis and large scale black outs because somehow our power sector have not generated enough financial muscle to cater to increasing production levels at higher prices. Intermittency is a major risk for thermal generation and not for renewables.

As consumers of electricity, we have not been given choice over the supply of electricity. Imagine, if someone wants to drive a Honda in this country but is only given an option to drive a Suzuki. We have been told for long enough now that renewables are expensive and therefore not for us. But same analogy does not hold for automotive industry. In the auto industry, people do buy expensive cars, small cars, hybrid cars, eco-friendly cars and at the same time gas guzzlers. But this is not the role of policy makers to decide which car should I purchase. Consumers should be given a broad based choice to pick and choose from newer technologies and efficient technologies. Right now, we have been given only an obsolete option for electricity generation which is expensive and at the same time less efficient. We need to enlarge our menu, open up more choices, benefit from renewable energy prices of today and use current low thermal prices to plan an effective transition from this gigantic, inefficient power sector to a new, efficient one.

 

Financing Renewable Energy in Developing Countries: Business Models and Best Practices

The World Bank has reported that an estimated 1.29 billion people in 2008 lived below $1.25 a day, equivalent to 22 percent of the population of the developing world. Almost over three billion people live on less than $2.50 a day and at least 80% of the world population lives on less than $10 a day. The relationship between income poverty and energy poverty is also ubiquitous. Today, there are 1.4 billion people around the world that lack access to electricity, some 85% of them in rural areas. Without change in current policies, by 2030 the number of people without electricity will drop only by 200 million. Sub-Saharan Africa continues to remain one of most the electricity deprived areas of the world. Further, the number of people relying on the traditional use of biomass is projected to stay same by 2030.

However, traditional finance mechanisms are not applicable in rural areas. Rural populations are spread out often in small pockets with dispersed locations and hence conventional grid is difficult to extend to such areas. As a result of low population density, difficult terrain, and low consumption, rural electricity schemes are costly to implement (Tomkins, 2008, p. 48). Project financing is virtually not possible since project cash flows are not adequate. In addition, low rural incomes can lead to problems of grid affordability and maintenance. Also, long distances mean greater electricity losses and more expensive customer support and equipment maintenance. Thus rural electrification projects have often required subsidies to make them financially viable (Tomkins, 2008).

The resources future publications take a deep dive into one of the most comprehensive studies on financing of renewable energy in developing countries. Download the full publication here and if you are interested in executing small energy projects, feel free to contact Resources Future at info@resourcesfuture.com

 

Pakistan Energy Access Report 2018

Access to electricity

Pakistan continues to struggle to provide for sustainable energy access across the country. Official data shows that energy access figures are in the range of 99% but the reality continues to be otherwise – with approximately more than 40% of the population connected to unreliable and potentially outdated and ill-equipped electricity grid. Provision of electricity is critical to Pakistan as the entire developmental agenda of Sustainable Development Goals (SDGs) hinges on it. On the regional scale, India’s has committed itself to electrifying households and provide for universal electricity access by 2020s, with renewables accounting for about 60% of those who gain access. In sub-Saharan Africa, the access rate has grown to 59% in 2030, from 43% in 2016, however, the number of people without electricity access in the region begins to grow again as efforts fail to gain momentum.

This report talks about improving energy access in Pakistan. To read the full report, including key recommendations for improving energy access please download the publication Energy Access Report Pakistan here.

— If you are working on energy access in Pakistan, let Resources Future provide its latest set of energy access data in Pakistan. Our repository house data from wide range of previous data sets, governmental statistics and private sector publications, giving you easy, hands on data for your project.–