ISLAMABAD: The new generation tariff and benchmarks for K-Electric (KE) under the MYT mechanism for 2023-29 have sparked conflict within the NEPRA Authority. Mathar Niaz Rana, Member (Tariff and Finance), has rejected several recommendations from his colleagues, expressing concerns that various components of KE’s current generation tariff could lead to increased consumer tariffs and may not adhere to prudent cost practices.
Well informed sources told NewzShewz that Mathar Niaz Rana is of the view that several components in KE’s current generation tariff are likely to escalate consumer tariffs and may not align with prudent cost practices.
Sharing his views in writing, Mathar Niaz Rana has stated that the dispatch factor of KE power plants BQPS-I (Unitl-6), KCCPP, KTGEPS and SGEPS has been decreasing since 2019. It has substantially reduced in FY 2023 after induction of BQPS-III (Unit I and 2).
KE presently also does not have firm GSA with SSGC, resulting in very nominal dispatch of power plants like KTGTPS & STGTPS. These plants also may not operate due to non-availability of gas. Moreover, KE’s current share from the National Grid is approximately 1,000 MW, expected to increase proportionally up to 2,600 MW once interconnectivity is established. KF is also actively working on the option of induction of renewable energy.
These plants will get payments many times their actual RAB under the proposed tariff structure over the remaining proposed period without supplying much energy to the system for the reasons explained above. Moreover, the per unit O&M cost of these power plants is also on a high side.
Considering the above factors, these power plants may be given Take and Pay Tariff for the control period. KE may consider developing a proposal for decommissioning these old plants in view of less expensive power options becoming available to KE.
He says that considering the dispatch factor and efficiency of BQPS-II and BQPS-III (Unit 1 & 2), these power plants may be given Take or Pay Tariff for the control period subject to following Paras: –
Take or Pay Tariff for Plants on Backup Fuel HSD: Sanctioning a “take or pay” tariff structure for KE plants operating on backup fuel i.e. HSD would not be a prudent decision, as HSD fuel being expensive would be on lower end of the merit order, are unlikely to operate but would nevertheless become eligible for capacity payments, which would otherwise be deducted due to the plant’s non-availability on its primary fuel. The imposition of such capacity payments on consumers may not be justifiable. Therefore, authorizing a “take or pay” tariff for plants on backup fuel (HSD) may not be allowed.
Take or Pay for Dedicated Contract for RLNG Supply: the approval of a Take-or-Pay fuel arrangement for RLNG would result in the out-of-merit operation of either BQPS-II or BQPS-TII if fuel prices disrupt the merit order. This is particularly likely following the introduction of central dispatch, the increase in power imports by KE from CPPAG, and KE’s expansion of self-generation through renewables. Consequently, the associated costs would be passed on to consumers through monthly Fuel Cost Adjustments (FCAs).
The argument that similar arrangements exist in some public sector plants is unconvincing, as these arrangements have resulted in the generation of out-of merit operations for many of these plants, an issue that has been raised in nearly every ECA hearing. Secondly, the government is actively exploring ways to prevent the risks associated with Take-or-Pay arrangements for RLNG from being passed on to consumers. As a private sector utility, NT has the flexibility to tailor and negotiate RLNG contracts in a manner that mitigates these risks— a flexibility that government-owned RLNG plants do not possess. Therefore, KE’s request to incorporate the Take-or-Pay arrangement of the RLNG contract into the tariff is unjustified, as it runs counter to consumer interests and should not be permitted. If this decision is made now, IKE will have ample time before the implementation of central dispatch, the increase in power imports from CPPAG, and the expansion of renewable generation, to negotiate more consumer-friendly RLNG contracts.
Therefore, in my opinion, that the RLNG fuel arrangements of NT now and in future should not be allowed on Take-or-Pay basis.
Dollar-based Indexation on Return on Equity (ROE): The Authority has allowed 14% dollar based ROE to IKE which is excessive and unfair. Most of the generating units of NT are Brownfield based on utilization of old existing assets. The rationale for high returns for new IPPs usually stems from compensating higher risks and uncertainties associated with new projects, which don’t seem applicable in this case. Many of KE’s plants, with the exception of BQPS-III, have substantially repaid their debts and are exposed to lesser risks compared to any new investments, which warrants consideration for a lesser return.
Furthermore, with approximately 66.40% of KE’s equity being foreign, applying dollar-based indexation on the ROE across the entire equity base; effectively allows KE to earn a dollar-denominated return on the 33.60% local equity portion. This not only over-compensates the local equity but also subjects KE’s consumers to unnecessary foreign exchange risk, particularly from Rupee-Dollar depreciation, on the local portion of the equity.
The decision to giant KE a 14% dollar-based ROE in the generation tariff; sets a significant precedent that other IPPs) might seek to follow. IPPs that currently receive their ROE in Pakistani Rupees or at a lower rate may now push for similar dollar-based indexation on their returns, arguing for parity under the regulatory framework. Such a shift could have broader financial implications, ultimately increasing the burden on consumers by exposing them to currency depreciation risks and driving up overall returns for power producers.
The argument that KE was previously granted a 17% dollar-based return in the last MYT Tariff and is now being allowed a 14% dollar-based return in the current MYT is fundamentally flawed due to a mis-comparison. The previous MIT was performance-based, where cost recoveries were linked to the energy sent out. In contrast, the current MIT guarantees cost recovery with a fixed return, regardless of the energy sent out. Therefore in my opinion the return may not exceed USD based return of 11.5% for foreign equity. Whereas for PKR equity, the return may not exceed 15.5% (11.5% + 4%), as per the Independent Consultant’s report presented to the Authority on March 01, 2022.
Indexation of O&M Component: In the new MYT, O&M component has been divided into local and foreign portions. The foreign O&M component is now indexed to both the US -CPI and the dollar exchange rate, while the local portion is indexed to the local CPI. Previously, KE’s O&M costs were indexed solely to the local CPI. Given that KE manages its O&M in-house, it would be fair to continue with the previous practice of O&M indexation i.e. on local CPI basis in the current MYT as well, in order to protect the consumers from exchange rate variation and impact of US-CPI inflation.
Outage Period: Technical Section recommended outage allowance @ 8% for BQPS-III, therefore, allowing outages @ 10% , would increase capacity payments for the additional allowance period. The capacity charges of 2% outage hour will be borne by consumers. Therefore, the outage period over and above technically recommended percent is not prudent and may not be allowed.
According to Member Finance and Tariff, in 2017, Kolachi Portgen submitted a tariff petition to NEPRA, indicating an availability factor of 92%. This petition, intended for KE as the purchaser, was based on the same machinery and technology subsequently utilized by KE for BQPS III. The 92% availability factor in Kolachi Portgen’s petition suggests that a thorough analysis was conducted by both ICE and Kolachi Portgen, confirming that such an availability factor was both realistic and achievable. Furthermore, other gas-based combined cycle plants in Pakistan, including Haveli Bahadur Shah, which served as benchmarks for BQPS III, were also allocated an availability factor of 92%. Additionally, KE’s Gas Supply Agreement supports an availability factor of over 92%.
Regulatory Asset Base (RAB) of BQPS-III: KE requested investment approval for the BQPS-III plant in its MYT Review Motion filed on April 20, 2017, with a project completion target by December 2019. The Authority approved this request on October 09, 2017, allowing KE to earn a Return on Regulatory Asset Base (RoRB) from FY-2018 to FY -2019, with tariff provisions for depreciation and WACC starting in FY-2020. However, despite the initial timeline, construction began in FY-2019 and the plant was only operational by the second half of FY-2023.
Accordingly, KB continued recovering both depreciation and RoRB for BQPS-III during the previous MYT period.
Now KE has requested the approval of the tariff of BQPS-ITI under the costplus mode. The Authority has decided to base the financial statements of the company to compute the allowable costs associated with BQPS-III and the Authority has not deducted the cumulative amount of RoRB and depreciation of Rs. 53.9 billion. This leads to excessive returns and this would duplicate recovery of certain costs for KB’s BQPS-III, a decision with which I respectfully disagree. Guiding principle as given in Act speaks that the Authority should only allow prudently incurred cost, which means assessing true and fair cost of project and any amount already paid to KE should be deducted from the allowable costs to avoid duplication.
Additionally, KE should provide complete documentation for the RAB (Rs. 103 billion) to allow the Authority to verify and assess its prudence and reasonableness, as is required for other IPPs under the cost-plus tariff regime. The Authority in the earlier MYT, approved cost of Rs. 72 billion for BQPSIII, which included upfront impact of exchange rate and other associated risks. By taking actual cost in the financial statements of KE, the Authority is allowing exchange rate variation beyond the allowed cap.
” In my view, the correct approach would be to allow the ROEDC amount related to the allowed construction period to the RAB and deduct the earlier allowed amounts of depreciation and RoRB from the previous MYT pertaining to the period in which the project was delayed and was not operational, to determine the prudent cost for KE’s BQPS-III,” he added.
Mechanism for Availability of Plants: As KE would be the System Operator (SO) for its own plants, therefore; a transparent verification mechanism of availability of KE plants needs to be defined, as it is not already available. In CPPA-G system, every plant declares its availability to SO based on which capacity charges invoice is processed for payment. These plants also undergo an annual capacity test to determine the revised capacity, which forms the basis for capacity payments. Therefore, considering future central dispatch and single grid code, NPCC being the SO, needs to ensure availability and operations of KE plants like other IPPs. Further it is recommended that a directive be issued in this tariff to ensure annual capacity tests are conducted for KE’s plants.
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