An interview with Nadeem Babar – PM’s Special Assistant on Petroleum
Nadeem Babar is a senior executive with extensive global experience in power generation, infrastructure finance and corporate finance. During his career, he has developed, financed and/or managed over 150 power plants of all commercially available technologies, as well as other energy sector assets. He has also been involved in social sector development, especially education.
Mr. Babar has an extensive international investment banking and project finance experience. He is the founder and was the CEO of Orient Power Company (Pvt) Limited until August 2018. He has served on numerous boards in the past. Currently, he serves as the Chairperson of Task Force on Energy Reforms. He is also a board member of Port Qasim Authority, Sarmaya-e-Pakistan and an independent director on the board of Samba Bank. He is the chairman of the board of Progressive Education Network, a section 42 company that runs 226 adopted government schools, with over 48,000 students.
Mr. Babar holds a M.S. in Civil Engineering Management from Stanford University, a B.A. in Economics from Columbia University and a B.S. in Civil Engineering from Columbia University. He was a member of Phi Beta Kappa (Liberal Arts) and Chi Upsilon (Civil Engineering) honor societies for academic excellence.
Last time BR Research met him in his capacity as the Chairperson Energy Reforms Taskforce, he talked at length about his plans to address the structural issues in the power sector and addressing the circular debt. BR Research sat down with Mr. Babar again recently in his capacity as PM’s Special Assistant on Petroleum where he discusses the issues faced by the petroleum sector, particularly the gas sector reforms that the government has embarked upon. The edited transcripts of the conversation are produced below:
BR Research: Can you share the progress in the power sector for targets you shared the last time we met?
Nadeem Babar: I mentioned four actions in the power sector the last time we met. One was to bring the power tariff close to the cost after inclusion of funded subsidies. In the latest two quarters of 2019 so far, we have seen some currency movements, the impact of which will come in the future; otherwise the tariff includes and trues up everything including the capacity payments and the indexations till the beginning of this year.
The second thing I talked about was the elimination of unfunded subsidies. The total quantum of subsidies from the Tariff Differential Subsidy (TDS) model, which is roughly Rs240 billion, has been included in the budget. As per the new mechanism decided with the government, this amount has been given at the disposal of the Ministry of Power that has just appointed an audit firm, where they will submit the subsidy claim to the audit firm now. This will streamline the process of disbursement of TDS
The third aspect we discussed was transmission. We have completed about 90-95 percent of the major issues we had identified last year. We are now onto the next round of identifying places to remove any further transmission constraints. The highest power that moved through the system in June last year was 19,600MW; whereas on July 4, 2019, we hit the highest power generation of 23,050MW, which means we moved an additional 3,500MW through the system in this one year without any problem.
The fourth issue was that of losses and theft. We launched the theft control program in November last year. We collected additional Rs121 billion revenue from this program in FY19. Taking out tariff impact and additional sale of units, the net improvement has been of around Rs104 billion.
We had estimated that by year ending June 2019, the accumulation of circular debt should be Rs320 billion accumulated for that year. We are pretty much on the spot of what we had targeted. As per the provisional numbers we are at Rs350-360 billion with one caveat: the TDS for May 2019 and June 2019 has not been disbursed. Including that, we will be close to our target. In July 2019 – the first month of FY20 with the revised tariff – the gap prior to TDS disbursement is only Rs20 billion and after TDS this will come down to single digits compared to Rs38 billion per month last summer.
We have targeted less that Rs100 billion circular debt accumulation for FY20 with the monthly average of Rs8 billion after accounting for TDS disbursement. If we continue at the same pace with no new enhancements, we will be on target. For first 6 months of FY21 when some of our technology interventions would have been initiated, we will be able to bring this monthly figure of Rs8 billion to practically zero. To get to these targets, nothing new is needed. Everything that we planned is in process; – initiated or well under way. We just have to take them to conclusion.
One last thing I would like to mention is that we initiated a campaign on theft control for gas, or what is known as UFG in the gas sector, in March 2019; and we have reduced UFG by one percent in these last four months in both Sui companies. This one percent achievement is a little deceptive as in few areas we did not seen any progress. Excluding those, the improvement in UFG has been over 1.5 percent. One of these problem areas is in KP where no gas is provided to regions that produce gas and has resulted in high losses. In the SSGC network, our key concern area is Balochistan where we need to make progress on cutting gas losses.
BRR: How do you explain the idle capacity that will further go up with new capacities coming online?
NB: Though idle capacity is there, there are some misconceptions. In peak summer months, the idle capacity is zero for a month. At the same time, there is about 2000MW of capacity that needs to be shut down due to very low efficiency but is still being run in the summer. If this is done, the one-month worth of full capacity utilisation can be extended to three or four months. But since our peak comes in summer, there will be times in spring and summer where there will be unutilised capacity since we have to plan for peak summer demand.
Second, people don’t realise the natural steady decrease in capacity utilisation from summer to winter is always there when hydel is added to the equation.
And third, the availability of solar and wind is between 20-30 percent. We can’t change that so there is idle capacities depending of the variability in wind or sun since these currently are not base load supply. On paper our installed capacity is 32,000MW; but the actual effective available capacity varies with seasons due to reasons I’ve just mentioned. It peaks in summers to about 23,000 to 24,000MW, and comes down in winters with hydel dropping down to practically nil.
BRR: Tell us about the broader gas sector reforms you have embarked upon?
NB: Within the petroleum sector we have five sub sectors: E&P, Refining and marketing (R&M), Pipelines and Gas Sales, LNG, and LPG. Within the next few months, significant reforms and policy changes are planned in all these sectors. You will see a whole list of policy and regulation changes going to the cabinet or the CCI in these five segments.
We had not awarded any block in the last 5.5 years prior to this government taking office, which has resulted in dwindling gas production. Every year, we are losing about seven percent of our production. This cycle is not instant; increasing exploration and production activity today will yield results in about 3-4 years. Even the existing players have been focusing more on development wells than exploratory wells to find new gas. To address why there has been a decline in drilling interest, we started consultations with all the industry. And surprisingly, pricing of gas was not the issue; we found out that it was the risk associated with policy changes in recent years that made oil & gas exploration unfeasible for many companies. One such example is the abrogation of signed contracts by introducing a new policy that took away some concessions and forcibly converted prior contracts to new terms.
Another example is that of wind fall levy on oil. The government decided to put a windfall levy on oil when the oil price touched $140. This essentially nullified the conditions and agreement signed in the existing contracts in terms of price being paid to the producer. Effectively, when the oil hit the peak of $140 a barrel, the price paid for local oil produced peaked out at just over $60.
Then in the E&P sector, the policymaker – Director General Petroleum Concession (DGPC) – itself is the regulator.
What we are doing is that we are making changes in the policy and separating regulatory function from the policymaking. So, there will be separate regulator for the E&P sector. Whether we merge it with OGRA or make a separate upstream regulatory body that is still being debated.
Another major thing we are working on is the old fields that got concessions 20-25 years ago signed at $1.75 to $2.50 that still haven’t exhausted completely. When you put in a new production well to replace the old wells, you are not taking the risk whether there exist any gas reserves, but you are still spending money to drill a new well. There comes an inflection point where the price of gas being offered in these old fields does not justify spending money to put new wells to extract that last volume of gas. There are many fields today that still have some gas reserves but it is not economical to take that gas out at the original prices in these contracts.
Our point of view is very simple. Agreeing to import LNG at say $9 versus not willing to increase the gas prices of these old fields for example from $2 to $3 to extract that last extractable volume out is a nonsensical decision, at a macro level. Do you make changes in the agreement? Because if you don’t, the operator and the partners will abandon the field as it becomes uneconomical. If the government plans to take it over, it can only auction it again at the current prices under the existing policy which is higher.
What we are now coming up with a change in policy for these end-of-life or marginal fields where the gas from these fields is offered a new price to replace imported gas.
BRR: What are your plans for the LNG sector?
NB: Our main issue in the LNG sector is that we have two signed contracts with two terminals where effectively, the entire obligation is that of the government. Our recommendation, which the cabinet has approved, is that the government is not going to make any new financial commitments or buy LNG, except for the two terminals it has contracted with.
We want the private sector to step in. In the last two months, we have given full authority to the private players for setting up an RLNG terminal and finding their market. Secondly, if the existing terminals want to remarket their excess capacity, they are free to do so. And if they do so, and the government is not using its full capacity, then effectively they are first remarketing our unused capacity, which basically means that the take-or-pay charge that we are supposed to pay them should first reduce before they sell off the extra.
Thirdly, while the third-party access rules for the pipelines have been issued, we are now working on third-party access rules for the terminals. Effectively, we are shifting the LNG business from a pure state-led monopoly to an open market where the government will be one player, and there will be other players from the private sector. Pipeline will be open access; the available capacity is advertised and live data is available to let people make decisions as per market conditions.
BRR: What other areas are you trying to reform?
NB: In the gas pipeline segment, we plan to separate the transmission from the distribution and split the distribution into smaller units not necessarily along the provincial lines. Why do we want to separate pipelines? SNGPL operating from northern Sindh to the northern tips of KPK is too large to effectively manage. Also, if we are to allow private gas, which will not be possible without separating transmission part of the pipeline and giving it open access. Our fundamental approach in the deregulation of pipeline is to separate the trunk transmission from both gas distribution companies and combine them into a single transmission company, which will be open access. The distribution should be split in my opinion into six distribution companies and privatised where possible.
We are also finalising the laying down of the third major trunk line, because our existing trunk lines are running on full capacity. We really don’t have much room to add gas to go from south to north whether it’s LNG or domestic gas. We will take this third line to the ECC and then to the cabinet towards the end of September for approval.
BRR: Let’s talk about the downstream refining segment.
NB: Refining and marketing has three segments: refineries, OMCs and retail. I believe that except PARCO refinery, all other refineries should be shut down because they are too old and too inefficient. Because of its location, maybe I give some leeway to Attock Refinery as well.
We are currently working on two new refineries. Work on PARCO Coastal Refinery will start from the beginning of next year. It will be a 250,000-barrel top of the line deep conversion refinery and will take 5 years to complete. Because of the delay in the project, the cost of the project has gone up and PARCO does not have the financial capacity to implement the $6-7 billion refinery itself. Already UAE government has 40 percent shareholding through PARCO and it is ready to increase its position directly or through another UAE-based company.
The second refinery is the Saudi refinery which will take time. We are working on its feasibility, and I can tell you that development work is happening at a good pace.
Another related fact is that we have added a provision in the budget that those refineries that are willing to go into deeper conversion will have income tax exemption and custom duty exemption on such conversion projects as with new refineries. PRL is working to benefit from this provision.
BRR: How are you dealing with the FO crisis?
NB: Our daily FO production in around 8-9k tons, out of which 2k tons is used by general industry. So, we have about 7k tons of FO to deal with, which was previously taken up by the power sector. Byco’s one unit is not operating for some time, while Attock’s production is around 1,100 tons. ATRL gets all the crude from the north region in Pakistan and produces low sulphur furnace oil. What we have done in the previous few months is that we have sent Attock’s entire LSFO production to KAPCO.
Why are we doing it this way? There are two reasons: exporting Attock’s FO is uneconomical given the freight. Attock will be reasonably secure if KAPCO runs on fuel oil only for a month and a half in the year. We expect that in winters when the gas will be diverted to domestic sector and we are not able to provide gas to KAPCO, it will run on fuel oil for a few days in winters. So when I say that we want to end fuel oil being used in power sector, it means that other than a short window in winters when gas is diverted to domestic sector, and 15-30 days of peak summers, fuel oil won’t be used in the power sector.
In this context, the domestic production of 2,700 tons of PARCO and 1,100 tons of Attock will be consumed in the power sector for another 1-2 years. The production of fuel oil by coastal refineries, which is around 4000-5000 tons per day is the issue. Last year when this issue erupted, we made a mechanism for export of furnace oil with consultations with the refineries where we agreed to give them financial support for six months, while they developed export channels. Almost everyone agreed, but then tensions with our neigbours resulted in increase in demand for a different slate of petroleum products for defense purposes, and everything went on the back burner. This year, we will revive the plan and ultimately get the refineries to export excess fuel oil, until they upgrade.
BRR: What are the issues of the OMCs and the retailers?
NB: The issue with the OMCs is that the regulation on the storage of oil was formed in a reactive mode after the crisis of December 2015, and it has some serious structural issues. They are not thought through. Big players that have over 800 fuel stations in the country have not been able to setup new stations due to these storage regulations by OGRA. We need to fix this storage concept; rather than focusing on storage, big players talk of “inventory in country” and inventory turnover to lower cost of storage, which is more sensible to address shortage issues.
Another serious issues that the OMCs, refineries and to some extent retailers face is OGRA’s decision to factor in exchange rate fluctuation in the cost of product. In the last one-year exchange rate has moved so quickly that there is much variability in the amount at which the orders had been placed, versus the amount that was actually paid. There was a lot of agitation, and OGRA changed the regulation to end of monthly exchange rate application. While this addressed the volatility in the exchange rates, it fails to address the second factor that oil imports cannot be hedged as per SBP regulations and payments may come after the end of the month. This has resulted in the accumulation of over Rs20 billion of unrecovered costs relating to exchange movement. On the other hand, the ECC decision was to use the actual cost to make fuel price calculations. These losses due to exchange movements have been detrimental to the refineries’ and OMCs’ profitability.
The issue with the retailers is that the margin that they were given many years ago is completely off balance with today’s inflation and cost. We need to fix this as well.
BRR: Let’s talk about the LPG sector now.
NB: In the LPG sector, we are producing around 2,200-2,300 tons per day domestically on average. During peak winter times, the demand rises to 3,200-3,500 tons per day, while in summers it is around2,700-2,800 tons per day. Previously, the price at which LPG was being sold had no connection to the cost. Domestic selling prices have ranged from PKR 50,000 to 80,000 per ton. Price volatility was rampant and supply in winters became inconsistent.
To address these issues, we are coming up with a new policy in the next 30-60 days. There are four major LPG producing countries in the region: Iran, Oman, UAE, and Qatar. What we are recommending is to make a weighted basket of the indices of these four countries as the benchmark, then using an average of freight to Karachi as a levy, and peg the domestic price to the weighted basket to bring them on a level playing field. This will make supply consistent and price relatively stable.
BRR: DISCOs have been a top priority for privatisation for a longtime. What’s the progress?
NB: While a lot of work is being done in the regard, there is a discussion going on between the various government stakeholders over the timing of the privatisation process. I was asked to make a report on the privatisation of DISCOs about five months ago, which I submitted to the cabinet committee on Privatisation back in April.
I proposed that we split some DISCOs into smaller units. Out of the resulting 16-17 DISCOs, around 11 can easily be privatised, and should be privatised immediately, while around 5-6 DISCOs that aren’t yet ready can be handed over to the provinces, or continue operations in present structure with the condition of a subsidy commitment, until they get ready.
Overall, it is expected that some of the first DISCOs will come up for privatisation within 1-2 years, but how many eventually get privatised is being discussed.