United Power Generation & Distribution valuation report: fair value BDT 79.7–118 (Oct 2026)

Thesis: power contracts that run out by 2039 put United Power's fair value range at BDT 79.7-117.8, base 94.3

United Power Generation & Distribution Company Ltd. (DSE: UPGDCL) is a Bangladeshi gas and HFO independent power producer (IPP) with 845 MW in operation across eight plants, including 195 MW at its 92.4%-owned subsidiary United Ashuganj Energy [2 p.10]. It makes money in two ways. Its Dhaka and Chattogram EPZ plants (154 MW) sell electricity and steam directly to factories in the export processing zones under agreements with BEPZA, and sell surplus power to BPDB and BREB. Its other plants sell only to the Bangladesh Power Development Board (BPDB) under power purchase agreements (PPAs). Those pay a capacity charge for being available plus an energy charge that passes fuel through [1 p.56]. The sponsor, United Group (through United Enterprises & Co.), runs the plants through its O&M company UEPSL [1 p.38].

The latest period here is FY2026 (year to 30-Jun-2026), but the audited FY2026 statements are not yet filed. On 28-Oct-2026 the board announced consolidated EPS of BDT 15.94 (FY2025: 20.66), NAV per share of BDT 83.33, operating cash flow of BDT 12.00 per share and a 60% cash dividend (BDT 6.00), with a record date of 19-Nov-2026 [3]. These are labelled 'DSE announcement, audited statements not yet filed'. Line items come from the FY2025 annual, the full FY2025 annual report and the nine-month (9M) FY2026 interim to 31-Mar-2026. Note: the model will be updated in place when the FY2026 annual is filed.

Our view: UPGDCL is the run-off of contracted cash flows, not a growing utility. Capacity payments were BDT 11.6bn of FY2025's BDT 39.1bn revenue [1 p.37] and most of its profit. The two small BPDB gas plants end in 2027, UAEL in 2030 and the Anwara and Jamalpur HFO plants in 2034; only the EPZ plants run to 2038-39 [2 p.10]. We value each contract group to its end, with no perpetuity, at a 15.6% cost of equity. That gives a fair value range of BDT 79.7-117.8, base BDT 94.3 (probability-weighted 94.6). The price of BDT 112.2 (29-Oct-2026) [4] is inside the range, between our base and bull cases.

Five-year record: ROE of 20-31% and payout cut from 99% to 31% as BPDB arrears grew

The five-year record shows a profitable business with deteriorating cash conversion. Revenue swung between BDT 30.6bn and 49.4bn as HFO dispatch rose and fell with BPDB's fuel budget. Gross margin ranged from 25% (FY2022-23, when HFO pass-through revenue was high) to 39% (FY2021) [6 p.127] [6 p.129]. Profit attributable to owners was BDT 8.0-12.0bn every year, and return on average equity ranged from 20% to 31%, with a median of about 25% [7 p.118] [1 p.12].

The dividend tells the story of BPDB's arrears. The company paid BDT 17.0 a share (170%) for FY2021 and FY2022, about 90-99% of earnings. It cut to BDT 8.0 for FY2023, BDT 6.0 for FY2024, BDT 6.5 for FY2025 and BDT 6.0 for FY2026, a payout of 31-43% [6 p.129] [6 p.188] [3]. Cash went into funding BPDB receivables and HFO stocks instead. Our forecast payout is 40% while arrears stay high, then the five-year median of about 60% from FY2029, and 100% from FY2035, when only the EPZ plants remain and nothing is left to reinvest in.

The balance sheet changed shape over the same five years. Property, plant and equipment fell to 74% of its FY2021 level as plants were depreciated towards their PPA ends. Trade receivables rose to 2.9 times their FY2021 level, and short-term loans to 3.75 times [6 p.126]. In other words, profits were reinvested in BPDB's arrears, not in new plants. The 2023 amalgamation of United Energy, United Anwara Power and United Jamalpur Power into the listed company simplified the structure and removed the minority leakage on those plants; only UAEL now has outside shareholders, at 7.6% [2 p.10]. Figures before FY2024 are as originally reported, before that merger.

Our forecast ROE of 16% in FY2027F and 12% in FY2031F is below the 20-31% history. There are three reasons. The supplemental tariff bills that lifted FY2025 do not recur. Equity has grown to BDT 48bn while the contract base is shrinking. And retained cash earns a deposit rate, not a plant return. A peak year like FY2025 (31%) is not 'normal' for valuation purposes; neither is FY2023's 25% with full HFO dispatch.

Plant registry: 81 MW of BPDB contracts end in 2027, 195 MW in 2030 and 415 MW in 2034

The plant table in the March 2026 interim is the core of the valuation [2 p.10]. Every BPDB contract has a fixed end year, and the company depreciates each plant to its PPA end, having dropped the earlier assumption that contracts would be extended [1 p.21]. The 53 MW Ashuganj plant's rental contract expired in 2018 and was extended [1 p.16], but it has reported no sales in any of the last five years [6 p.124]. The 50 MW Leviathan Global plant at Karnaphuli EPZ is built but idle because of a gas-tariff dispute with Karnaphuli Gas [2 p.10].

The first question for any IPP is which contracts end within twelve quarters. For UPGDCL that is Ashuganj 53 MW and Sylhet 28 MW in 2027. They are small: we give them 8% of the parent's capacity payments, an assumption because the filings do not split capacity payments by plant. With Ashuganj idle, that may be generous. Our base case runs each BPDB plant for one 'no electricity, no payment' (NENP) year at half its contract-period dispatch after its PPA ends, then nothing. The bear assumes shutdown and the bull a five-year renewal at half the old capacity rate. We give the EPZ plants nothing after 2039 even though their factory customers will still need power. That is a conservative choice.

Utilisation: 40% in FY2025, with Anwara's 300 MW HFO plant at only 9%

Dispatch is set by BPDB's merit order and fuel budget. Group utilisation rose to 40% in FY2025 from 32% in FY2024, on 2,522 GWh of generation [6 p.39] [6 p.47]. The spread across plants is wide. The Chattogram EPZ plant ran at 86% because its factory customers buy all it makes, and Dhaka EPZ at 55%. The Anwara 300 MW HFO plant ran at only 9.2% (22% a year earlier), because BPDB calls oil plants last when it is short of money for fuel. UAEL's 195 MW gas plant jumped from 15% to 56% when gas supply improved [6 p.188].

Over five years HFO generation fell from 2.3 TWh (FY2022) to 0.67 TWh (FY2025), while EPZ sales held at 0.7-1.0 TWh [6 p.124]. HFO plants earn their capacity payment whether or not they run, so lower dispatch mostly reduces pass-through revenue, not profit. That is why profit held up as revenue fell, as reported by the Financial Express [8]. For gas plants the binding constraint is Petrobangla's gas allocation. Domestic output is falling, and in winter gas is diverted to fertiliser factories and households.

Our base dispatch factor is 100% of the 9M FY2026 run-rate, after a separate Q4 seasonal line. The bear (85%) and bull (115%) move it by 15% for two years and then fade back. That is a smaller move than the 14-24% yearly revenue swings of FY2022-25. Because fuel is a pass-through and capacity payments are fixed, each 5% of dispatch moves FY2027F EPS by only about BDT 0.38.

Contracts: capacity payments are 37% of FY27F revenue and fall to zero by FY2035

In FY2025, electricity revenue of BDT 38.7bn was made up of capacity payments of BDT 11.6bn, fuel payments of BDT 15.3bn, energy payments of BDT 10.1bn, supplemental bills of BDT 0.86bn and true-up bills of BDT 0.60bn [1 p.37]. Fuel is a pass-through: the PPA reimburses gas or HFO at the regulated price, and true-up bills cover the gap between the billing and payment-date exchange rates [1 p.56]. Supplemental bills are a catch-up on the bulk tariff after earlier gas-price rises. In 9M FY2026 they were still BDT 869.5mn [2 p.29], all booked in the first half. The company said Q3 FY2026 EPS fell because of 'the absence of supplemental revenue' [3]. We include them in FY2026E and forecast none from FY2027; they are kept out of the run-rate.

In 9M FY2026 capacity payments were BDT 8.80bn of BDT 24.01bn revenue [2 p.29]. Annualised, that is BDT 11.7bn, of which BDT 3.7bn is UAEL's. We apply a 5% contract-review haircut in the base case (10% in the bear, none in the bull). The Daily Star has called for capacity terms to be renegotiated [10], and the Financial Express reports earnings pressure on listed IPPs as policy shifts [9]. A 15% haircut would cut fair value to BDT 88.3.

Industry: BPDB pays IPPs late, partly in bonds, and the state wants out of capacity payments

BPDB is the single buyer of grid power in Bangladesh. Much of the private capacity added after 2010 was contracted with capacity payments, which left BPDB paying for idle plants while its tariff did not cover costs. The result is chronic arrears to IPPs. UPGDCL collected BDT 23.5bn in cash against BDT 34.8bn of revenue in FY2024, and BDT 31.6bn against BDT 39.1bn in FY2025. BPDB settled BDT 16.6bn and BDT 4.3bn of receivables with special bonds in those two years [6 p.45]. Those bonds turn an operating receivable into a government security.

Policy has turned against capacity payments and oil-fired plants. The interim government's review of power contracts, the expiry of old rental plants on NENP terms (SPCL's 86 MW is an example) and the push to cut BPDB's subsidy all point the same way. Plants are renewed on energy-only terms, if at all [10] [9]. UPGDCL's own peer comparison shows it earning far more than the other listed IPPs. In FY2025 its EPS was BDT 20.66 against 0.29-3.19 at Khulna Power, Summit and Doreen [6 p.123], mainly because its HFO plants still carry capacity payments and its EPZ business sells at retail prices.

What this means for each line of UPGDCL's model is specific. Grid demand drives only the pass-through revenue of the BPDB plants, because BPDB decides how much to dispatch. Capacity payments depend on availability, not demand, so they move only if the contract terms change, which is the review risk. The EPZ line depends on export-factory activity in the Dhaka and Chattogram zones, which has held up: EPZ sales were 0.84 TWh in FY2025 against 0.77 TWh in FY2024 [6 p.124], and steam sales grew 45% as new factory customers signed up [6 p.47]. The fuel line depends on regulated gas and HFO prices, but because the PPAs pass fuel through, a price rise lifts revenue and cost together and leaves the spread largely unchanged.

Competition for UPGDCL is not about price in the usual sense. New plants, including large coal and LNG-fired units, sit ahead of old HFO plants in BPDB's merit order, which explains Anwara's fall to 9% utilisation. The EPZ plants face no direct competitor inside the zones, but factories can also take grid power through BEPZA. The listed sector itself is shrinking: Khulna Power's HFO units shut when their PPAs expired, and Shahjibazar runs on an energy-only renewal. UPGDCL is the best placed of the listed IPPs, but it is on the same path.

Gas and EPZ: BDT 8.69bn of captive-rate gas claims are unprovided

The EPZ business sells power to factories in the Dhaka and Chattogram export zones. In 9M FY2026 it billed BEPZA BDT 4.0bn, BREB BDT 0.74bn and private customers BDT 0.70bn, plus BDT 0.37bn of steam to ten zone factories such as Universal Jeans and Pacific Attires [2 p.29]. These customers sit outside BPDB's payment queue: BEPZA owed only BDT 0.38bn in March 2026 [2 p.17]. The EPZ plants are the longest-lived part of the group, contracted to 2038-39. The newer 47 MW Dhaka and 28 MW Chattogram units ran at 66% and 77% in FY2025 [6 p.188].

Gas price is the risk. The EPZ plants were built as captive plants and bought gas at the cheaper power rate. Titas Gas and Karnaphuli Gas now claim BDT 5.55bn and BDT 4.48bn of extra charges at the captive rate for 2018-2025. The company provided BDT 1.34bn and left BDT 8.69bn unprovided, which the auditor flagged [1 p.49] [1 p.3]. Since October 2023 UPGDCL has paid the captive rate, so the current margin already reflects it. We deduct the claim at 50% probability (75% in the bear, 25% in the bull); paying it in full would cut fair value to BDT 88.0.

For the model, the gas question shows up in three places. The EPZ spread already reflects the captive rate since October 2023, so no further cut is in the base. The historical claim is a one-off cash outflow, which we treat as a probability-weighted deduction in the bridge, not a cost in the forecast; if the FY2026 annual shows a provision for it, the bridge deduction falls by the same amount and fair value barely moves. And the idle Leviathan plant at Karnaphuli EPZ is tied to the same dispute: settling the tariff could start a 50 MW plant on a 30-year BEPZA agreement [2 p.10], which our bull case values only at half its book cost.

Taxes rise as holidays end. The 35 MW Dhaka and 44 MW Chattogram EPZ units became taxable in December 2023 and August 2024. The newer 47 MW and 28 MW units are exempt to 2028, and the BPDB plants to their contract ends [1 p.57]. FY2025 tax was only BDT 274.5mn on BDT 12.5bn of profit before tax [1 p.12]. From FY2029 all EPZ profit is taxed. We model tax at 27.5% of taxable EPZ and post-PPA profit plus about BDT 150mn of other tax, giving BDT 523mn in FY2029F.

Receivables: BPDB owed BDT 20.7bn in March 2026, about 311 days of its bills

BPDB's payment delays are UPGDCL's main working-capital swing. The receivable from BPDB rose from BDT 14.8bn in June 2025 to BDT 20.7bn in March 2026, and the company says it is owed nine to ten months of undisputed invoices [2 p.17]. Operating cash flow per share fell to BDT 7.22 in 9M FY2026 from 15.17 a year earlier, which the company blamed on collection delays from its main buyer [3]. Q4 then recovered, and full-year NOCFPS was BDT 12.00.

The delay is funded with debt. Short-term loans from HSBC, Dhaka Bank, City Bank, BRAC Bank and others cost 11.5-13.5% [2 p.25], and gross debt was BDT 8.1bn in March 2026 [2 p.2]. We assume BPDB pays at 300 days in June 2026 and 2027 and at 180 days from FY2029; the bear holds 360 days. When each contract ends, its receivable is collected, so the run-off releases cash. Paying 60 days slower would cost BDT 3.2 a share of fair value.

Related-party lending is the second balance-sheet issue. UPGDCL and UAEL lend to group companies through a central treasury, and the auditor notes these funding flows arise from BPDB's delays [1 p.3]. The balances moved sharply in 9M FY2026. On the asset side, the receivable from United Mymensingh Power fell from BDT 19.04bn to BDT 3.4mn, while the receivable from United Enterprises & Co. (UECL) rose from BDT 4.49bn to BDT 10.16bn; total related-party receivables went from BDT 23.53bn to BDT 10.29bn [2 p.18]. On the liability side, the amount owed to UECL fell from BDT 13.12bn to BDT 2.55bn, and the total from BDT 14.02bn to BDT 3.60bn [2 p.28].

The net position fell from BDT 9.51bn to BDT 6.69bn. Net of what UPGDCL owes it interest-free, UECL owes BDT 7.61bn, interest-bearing and on demand. In the bridge we add the BDT 6.69bn net balance and deduct a 30% haircut on the BDT 7.61bn net UECL exposure (50% bear, 10% bull), for BDT 4,411mn. The forecast earns no interest on these loans, so nothing is counted twice.

UAEL: the 92.4%-owned 195 MW plant adds BDT 14.6 a share of contract value to its 2030 PPA end

United Ashuganj Energy (UAEL) runs a 195 MW gas plant at Ashuganj, in operation since 8-May-2015 under a 15-year BPDB PPA ending in 2030 [2 p.10]. It ran at 56% in FY2025 [6 p.188]. Its capacity payment was BDT 2.78bn in 9M FY2026 (consolidated less separate) [2 p.29]. Its profit, inferred from the 7.59% minority share of BDT 147.6mn, was about BDT 1.9bn [2 p.3]. It is funded with 12% preference shares and a USD IPFF loan [2 p.24]. On 25-Oct-2026 it declared a 60% cash dividend, BDT 6.00 a share on 400.4mn shares [3].

UAEL passes the significance test (over 10% of profit). But it is consolidated and its cash flows are as contracted as the parent's, so we value it inside the contract-by-contract DCF rather than as a separate leg: we take 92.4% of its EBITDA and stop at the PPA end. A sum of the parts in the skill's sense does not apply, because no part is listed or has different economics.

Earnings quality: operating cash flow covered EPS in only two of the last five years

Reported profit and cash are far apart in single years. Operating cash flow per share was BDT 1.89 against EPS of 17.21 in FY2022, and negative BDT 0.88 against 14.01 in FY2024. It exceeded EPS in FY2023 (19.40) when BPDB paid down arrears, and nearly matched it in FY2025 (18.61) [7 p.118] [6 p.45]. Over FY2022-26 cumulative operating cash flow was BDT 51.0 a share against cumulative EPS of 81.7. The gap is the receivable build-up and the bond settlements, which are not cash.

Three other items lower earnings quality. First, supplemental and true-up bills (BDT 1.3-1.5bn a year in FY2024-25) are tariff catch-ups, not run-rate profit [1 p.37]. Second, UAEL's capacity revenue is straight-lined under IFRS 16, so booked revenue differs slightly from billing [2 p.29]. Third, O&M is bought at cost plus a fee from a group company, UEPSL [1 p.38]. On the other hand, the auditor's report carries an emphasis of matter but no qualification [3], and the plants are depreciated to PPA end, which avoids overstating book value.

Forecast: EPS of BDT 15.94 in FY26 (DSE), 14.32 in FY27F without supplemental bills, then 14.47 in FY31F after UAEL ends

FY2026E is built from named drivers, not a plug. The nine-month figures are annualised and then cut by a Q4 seasonal line: in FY2024 and FY2025 Q4 gross profit fell 18% and 16% short of four times the Q1-Q3 average [6 p.124], so we deduct 17% of run-rate gross profit every year. Supplemental bills enter FY2026E at their 9M value of BDT 895mn. That gives FY2026E profit to owners about BDT 190mn (0.33 a share) below the announced BDT 9,240mn. We show the difference as a residual until the annual explains it.

FY2027F revenue is BDT 30,239mn. That is capacity payments of BDT 11,147mn after the 5% haircut, plus energy and EPZ revenue at the 9M run-rate. Fuel is 70.3% of pass-through revenue, as in 9M FY2026 [2 p.29] [2 p.30]. Fixed O&M is BDT 2.3mn per MW. Depreciation stays at BDT 3,394mn and falls to zero for each plant at its PPA end. Net finance cost turns into income from FY2028F as BPDB arrears unwind and debt is repaid. EPS is BDT 14.32 in FY2027F and 16.68 in FY2030F. It falls to 14.47 in FY2031F without UAEL and to 7.77 in FY2035F without the HFO plants.

The balance sheet follows the same drivers. BPDB receivables fall from BDT 19,688mn (June 2026E) to BDT 9,956mn by June 2029F as payment days return to 180. As UAEL and the HFO plants end, their receivables are collected, and debt turns into net cash from FY2028F (BDT 29,065mn of net cash in FY2029F). Inventories and trade payables move with fuel cost (99 and 169 days, the March 2026 levels [2 p.2]). Capex is maintenance only, BDT 200mn a year, because no new plant has been announced. Operating cash flow is BDT 13,048mn in FY2027F and BDT 16,527mn in FY2028F, well above profit while arrears unwind, against BDT 6.96bn implied by the FY2026 NOCFPS [3].

Valuation: contract DCF and DDM give a fair value range of BDT 79.7-117.8, base 94.3 (6.6x FY27F EPS)

Method. Each contract group's EBITDA (capacity payment + energy spread - fixed O&M, after the Q4 seasonal cut) is discounted to its contract end. Group tax, maintenance capex, G&A and working-capital changes are discounted separately, and the working capital left at 2039 is collected in 2040. No value is added after 2039, and salvage or land value is zero because none is disclosed. The cost of equity is 15.6%. We discount at the cost of equity and deduct June-2026 net debt, because the debt is short-term working-capital funding, not project debt.

The DDM is BDT 33.0 a share below the DCF, for two quantified reasons. First, timing (14.9): the DCF counts receivables released by BPDB as cash at once, while the DDM pays dividends out of accounting profit, so that cash sits in book until 2039 even at a 100% payout (DDM 85.9). Second, retention (18.0): at our 40%/60% payout the retained cash earns the 6.21% average bank deposit rate (SBS Table-102), against a 15.6% cost of equity. Both are real costs to a minority shareholder in a group that has lent surplus cash to its sponsor. We weight the DCF 80% and the DDM 20%. F23 suggests 50% sum of the parts, 30% DDM and 20% P/E. We drop the P/E leg because we have no peer figures from filings on the same basis; the peer table is context only.

The base value is 6.6x FY2027F EPS and 1.13x FY2026 NAV, a 6.1% yield on FY2027F DPS and an EV of BDT 74.7mn per operating MW. Post-PPA cash flows are effectively zero in the base case, because one NENP year earns about its own O&M, and 12% of value in the bull. Both are below F23's 25% flag.

The bull is wider than the bear (BDT 23.5 above base vs 14.6 below). A five-year renewal of the BPDB plants adds value that the bear cannot take away: the bear's shutdown costs little, since the base's single NENP year roughly covers its O&M. The current price sits between our base and bull cases, so it implies roughly a partial renewal or faster BPDB payment.

A reverse check: the price of BDT 112.2 is 7.8x our FY2027F EPS and 1.35x the FY2026 NAV. To get there from our base, the market must expect either faster BPDB payment and a smaller sponsor-loan haircut, or a renewal of the HFO contracts after 2034 at a meaningful capacity rate. Our bull case, which assumes a five-year renewal at half the old capacity rate, full run-rate dispatch, no review haircut and 120-day BPDB payment, comes to BDT 117.8. The price is close to that case.

The EPS grid uses dispatch and the capacity haircut rather than F23's utilisation and BDT/USD pair. Fuel is passed through at the regulated price and FX differences are recovered through true-up bills, so the exchange rate barely moves profit; the capacity haircut does.

Risks: a 15% capacity-payment cut or the full gas claim each cost about BDT 6.0 a share

Each risk below is a line in the model. Contract review cuts the capacity-payment line. Lower dispatch cuts pass-through revenue and the energy spread. Slower BPDB payment raises receivable days and debt. The gas claim and the sponsor loans enter the valuation bridge. The bear case combines 25%-probability moves in all of them, so it sits below every single shock.

Two smaller items. The USD IPFF loan at UAEL and the HFO import letters of credit expose the group to the taka; in FY2024 it booked an FX loss of BDT 824mn [1 p.12], which fell to BDT 60mn in FY2025 as the exchange rate stabilised. Tariff true-up bills recover part of this. Second, the 53 MW Ashuganj plant has sold nothing for five years [6 p.124]. If it is carrying any capacity payment we may be too low; if not, our 8% allocation to the small gas plants is too high. Either way the effect is under BDT 1 a share.

• Governance: a net BDT 7.6bn owed by the sponsor and a central group treasury; dividends from tax-exempt UAEL profit are treated as tax-exempt on legal advice.
• Leviathan Global: BDT 2.5bn of work in progress idle over a gas-tariff dispute; we count 25% x 75% of it.
• Policy: an end to IPP renewals, or a forced renegotiation of HFO tariffs.
• Opportunity: settlement of BPDB arrears through bonds or budget support would release cash faster than our 180-day assumption.

What to watch: the FY2026 annual's Q4 detail, the 19-Nov-2026 record date and the 2027 PPA ends

• Record date 19-Nov-2026 for the BDT 6.00 dividend; AGM 23-Dec-2026, held digitally (DSE).
• FY2026 audited annual: the Q4 detail, the June-2026 BPDB receivable and any new gas-claim provision.
• Q1 FY2027 results (due about November 2026): dispatch and collections.
• 2027: Ashuganj 53 MW and Sylhet 28 MW contract ends - renewal or shutdown.

Model update note: this report uses the FY2025 annual, the 9M FY2026 interim and the FY2026 DSE announcement. The model will be updated in place when the audited FY2026 statements are filed.

FAQ

What is United Power's fair value range?

Our fair value range is BDT 79.7-117.8 per share, base BDT 94.3 (probability-weighted 94.6), from a contract-by-contract DCF to each PPA end (80%) and a DDM (20%) at a 15.6% cost of equity.

When do UPGDCL's power purchase agreements expire?

Ashuganj 53 MW and Sylhet 28 MW in 2027, UAEL 195 MW in 2030, Anwara 300 MW and Jamalpur 115 MW in 2034, and the EPZ plants in 2038 (Dhaka) and 2039 (Chattogram), per the company's plant table.

How much does BPDB owe United Power?

BDT 20.7bn on 31-Mar-2026, nine to ten months of undisputed invoices, up from BDT 14.8bn in June 2025.

What were UPGDCL's FY2026 earnings and dividend?

The DSE announcement of 28-Oct-2026 gives consolidated EPS of BDT 15.94, NAV per share of BDT 83.33 and a 60% cash dividend (BDT 6.00); audited statements are not yet filed.

Sources

1. United Power Generation & Distribution Co. Ltd. audited consolidated financial statements, year to 30-Jun-2025 · link · accessed 2026-10-31
2. United Power Generation & Distribution Co. Ltd. un-audited financial statements, nine months to 31-Mar-2026 · link · accessed 2026-10-31
3. DSE news archive for UPGDCL (FY2026 results and dividend 28-Oct-2026; quarterly EPS, NAV and NOCFPS disclosures 2024-2026; UAEL dividend 25-Oct-2026) · link · accessed 2026-10-31
4. AnalystBro market data: DSE prices for UPGDCL and DSEX (daily and weekly bars), 29-Oct-2026 · link · accessed 2026-10-31
5. Bangladesh Bank treasury auction page: 10-year bond cut-off 9.268% on 25-Oct-2026 · link · accessed 2026-10-31
6. United Power Generation & Distribution Co. Ltd. Annual Report 2024-25 (full report: directors' report, MD&A, five-year and operational highlights) · link · accessed 2026-10-31
7. United Power Generation & Distribution Co. Ltd. Annual Report 2022-23 (MD&A, peer table) · link · accessed 2026-10-31
8. The Financial Express, 'United Power lifts profit on deep cost cuts amid revenue slump' · link · accessed 2026-10-31
9. The Financial Express, 'Listed private power producers face earnings pressure amid policy shift', 6-May-2026 · link · accessed 2026-10-31
10. The Daily Star, 'Capacity payment terms must be renegotiated' · link · accessed 2026-10-31
11. AnalystBro model for this report (model.xlsx: Assumptions, statements, Valuation, Sensitivity) · accessed 2026-10-31