| Item | Content |
|---|---|
| Rating | Neutral |
| Target price range | RMB 4.9–5.4 (fair value in the base case; midpoint RMB 5.15) |
| Current price | RMB 5.26 (close on 2026-10-28, the sole price anchor for this report) |
| Market cap | approx. RMB 93.8 billion (total shares: 17.836 billion) |
| Time horizon | 12–18 months |
| Margin of safety | No substantive margin of safety (base-case fair value floor of RMB 4.9 is -7% vs. current price) |
GD Power is the conventional-energy integration flagship of China Energy Investment Corporation (CHN Energy), and in 2026 it is caught in a two-way squeeze of "falling power tariffs + rebounding coal prices": net profit attributable to the parent for the first three quarters was RMB 3.961 billion (-41.55%), with Q3 alone at only RMB 947 million (-69.34%). We forecast full-year attributable net profit of RMB 4.76–5.26 billion, about 13–21% below sell-side consensus (RMB 6.064 billion). What the market is currently pricing in is the 2027 recovery path of "full-year hydropower annualization + stabilization and rebound of long-term contract tariffs" — back-solving from the current price of RMB 5.26 at an 8.5% cost of equity implies roughly RMB 8 billion/year of sustainable attributable cash flow, which effectively treats the sell-side 2027E consensus (RMB 7.49 billion) as already realized and held in perpetuity. Our own base case puts the 2027E attributable midpoint at RMB 6.7 billion (partial tariff recovery, not full pass-through), corresponding to a fair value range of RMB 4.9–5.4, with a weighted fair value of about RMB 5.09 across three scenarios, -3.2% vs. the current price — valuation is broadly reasonable and odds are roughly symmetrical; most of the recovery dividend has been front-run, and the RMB 0.22/share dividend commitment (guaranteed minimum dividend yield of 4.18%) is the main downside protection. Over the next 12 months, four verifiable checkpoints (the December negotiation of 2027 annual long-term contracts, interim dividends, disclosure of acquisition consideration, and full annualization of Shuangjiangkou) will determine direction. Rating: Neutral.
Market environment: In a low-rate environment, the allocation logic for dividend-yield assets remains intact, but in 2026 the power sector is in an earnings headwind period of "falling tariff cycle vs. coal price reversal"; A-share coal-fired SOE power companies broadly reported double-digit declines in H1 attributable profit (Huaneng -28%, Huadian -20%, China Power -47%, while Datang rose +20% against the trend thanks to hydropower). The sector's pricing mechanism has shifted from "benefiting from falling coal prices" to an expectation game around "2027 tariff recovery + asset injection."
Most important sources of change (chronological): ① mid-to-late December 2026 — outcome of the 2027 annual long-term contract tariff negotiations (Guangdong's October monthly composite price was already up +RMB 84.4/MWh YoY and Jiangsu's +RMB 54.6, an early positive signal); ② Nov–Dec 2026 — rollout of the interim dividend plan; ③ by end of March 2027 — disclosure of consideration for acquiring 7 companies from the Group (13.54 GW under construction/planned); ④ commissioning of Shuangjiangkou's 4th unit and full annualization of hydropower in 2027.
Where the expectation gap lies: On the short end, the genuine expectation gap is in 2026E — sell-side consensus of RMB 6.064 billion implies a Q4 standalone profit of RMB 2.1 billion (2025Q4 actual was only RMB 385 million, which is hard to reach even after normalizing for tax items); a downward revision of consensus may weigh on the stock before catalysts materialize. On the long end (2027E), our midpoint of RMB 6.7 billion vs. the sell-side RMB 7.49 billion differs by about 10% — not a large divergence, but directionally critical: the current price requires tariffs to rebound, not merely stabilize. The extreme bull view (Guotai Haitong, 2026-09: 2026E ~RMB 8 billion, target price RMB 6.44) holds that hydropower growth is significantly undervalued, providing the coordinates for our bull scenario.
Primary stock drivers: 2027 annual long-term contract tariffs (each ±RMB 0.01/kWh ≈ ±RMB 1.2–1.5 billion in attributable net profit, directly determining the split between the base and bear scenarios); second, delivered benchmark coal price (long-term contract share ~99%, low pass-through coefficient from spot even if spot breaks RMB 1,000/ton — the real variable is 2027 long-term coal contract policy); third, delivery of hydropower volume and price.
Key evidence:
For Q4 standalone attributable net profit we take RMB 0.8–1.3 billion (a recovery from RMB 385 million in 2025Q4, reflecting partial normalization of tax and profit-attribution structure, but constrained by tariffs in the RMB 355–365/MWh range and winter peak fuel costs), implying a full-year RMB 4.76–5.26 billion. If the annual report confirms this forecast, "13–21% below consensus" will itself be a tradeable expectation-revision event.
Key evidence:
Neutral 2027 profit bridge: if tariffs merely "stabilize," contribution is zero; a rebound of ~RMB 0.3–0.5 cents/kWh contributes RMB 0.4–0.7 billion; plus full hydropower annualization (+RMB 0.45–0.9 billion), delivered coal falling back to RMB 800–830/ton (+RMB 0.3–1.4 billion), associate stabilization (+RMB 0.2 billion), and incremental generation from new units (+RMB 0.2–0.4 billion), totaling +RMB 1.5–3.6 billion, implying 2027E of ~RMB 6.2–7.2 billion. Reaching the sell-side RMB 7.49 billion would require a tariff rebound of over RMB 1 cent/kWh plus multiple variables landing at the high end — high coal prices (spot at RMB 1,000) do strengthen negotiating leverage, but the company's coal-fired generation is concentrated in East/North China and western Inner Mongolia; Guangdong/Jiangsu price-increase signals face regional discounts in transmission to the company's main provinces.
Key evidence:
Three layers of value: book NAV of RMB 3.44/share is the accounting floor (replacement-cost rough estimate ~RMB 4.7–5.8/share; the legacy Dadu River hydropower carries scarcity value but minority shareholders take the bulk); zero-growth EPV based on normalized attributable profit of RMB 5.5 billion / 8.5% cost of equity ≈ RMB 3.63/share (sensitivity: RMB 3.17 at RMB 4.8 billion, RMB 3.96 at RMB 6 billion — the conclusion that "the current price is ~30% above zero-growth value" is robust across parameters); the gap between the current price and EPV, ~RMB 1.63/share (~31%), is the growth option the market pays for "hydropower + injections," backed physically by 5,666.5 MW of hydropower under construction plus the announced acquisition of 13,540 MW of assets under/planned for construction, though most projects only commission in 2027–2030. The flip side of the dividend protection: if 2026E attributable profit is only RMB 4.76–5.26 billion, the RMB 0.22 floor implies a payout ratio of 75–82%; under a structure of cash acquisitions + annual capex above RMB 25 billion + RMB 5.8 billion of minority dividends, delivery depends on retained earnings and financing arrangements — the dividend floor is effective but not costless.
Key evidence:
In the short-to-medium term, the injection is a pure cash outflow (consideration undetermined plus tens of billions in subsequent construction capex), with profit delivery concentrated in 2028–2030 and coal-fired power accounting for over half; on an attributable basis, equity-adjusted profit from Xulong/Benzilan is roughly 40%. A potential offsetting variable: the company has precedent for raising its attributable share (raising Dadu River stake from 69% to 80% in 2022); consolidating the remaining 20% of Dadu River or the remaining 49% of Xulong/Benzilan would improve the dilution structure — no current commitment; an item to watch.
Key evidence:
One clarification: the "subsidy receivables of RMB 28.455 billion with a 7.6% provision ratio" often cited in market discussion actually refers to the entire accounts receivable balance (mainly electricity fee receivables) provisioned on a portfolio basis at end-2025 and its ratio, not a subsidy-specific measure; the provision ratio is in fact rising and impairments are narrowing — evidence for "managing profit through impairments" is insufficient. The real issue is cadence opacity: large single-quarter swings in tax settlement and profit-attribution structure lack proactive disclosure, making full-year results significantly less predictable than the smooth surface of the statements suggest — if 2026Q4 again shows single-digit (in hundreds of millions) standalone attributable profit without explanation, this discount factor will be reinforced.
| Metric (RMB 100M unless noted) | 2023FY | 2024FY | 2025FY | 2026Q1-3 |
|---|---|---|---|---|
| Revenue | 1,810.0 | 1,791.8 | 1,702.4 | 1,243.6 |
| Revenue YoY | — | -1.0% | -4.99% | -0.68% |
| Attributable net profit | 56.09 | 98.31 | 71.61 | 39.61 |
| Attributable YoY | +104.4% | +75.3% | -27.2% | -41.6% |
| Recurring attributable net profit | 48.70 | 46.66 | 67.76 | 38.14 |
| Recurring YoY | — | -4.2% | +45.2% | -40.6% |
| Gross margin | — | — | 15.54% | 12.41% (-4.34pp) |
| Operating cash flow | 425.84 | 556.40 | 536.68 | 376.52 |
| Free cash flow (OCF – capex) | -71.9 | -24.6 | +78.5 | +122.2 |
| Cash (period end) | — | 154.37 | 158.21 | 149.57 |
| Interest-bearing debt (short-term borrowings + current maturities + super short-term CP + long-term borrowings + bonds payable) | — | — | 3,043.3 | 3,183.6 |
| Debt-to-asset ratio | 73.92% | 73.40% | 73.45% | 73.55% |
| DPS (RMB) | 0.16 | 0.20 | 0.241 | — |
Note: 2026Q1-3 free cash flow = OCF 376.52 – capex 254.34; lease liabilities and long-term payables of ~RMB 14.6 billion are excluded from the interest-bearing debt measure above; net debt (interest-bearing debt – cash) ~RMB 303.4 billion; 2025 EBITDA rough estimate RMB 41.0–42.0 billion (net profit 13.73 + D&A 21.9 + finance costs ~6.0, this report's estimate), net debt/EBITDA ~7.3x — a typical asset-heavy, highly leveraged utility structure.
Explanation of YoY changes (items ≥ ±20%):
First-three-quarter revenue of RMB 124.36 billion (-0.68%) — volume growth (generation +3.15% YoY, controlled capacity up ~5.23 GW net YoY) largely offset the tariff decline; but attributable net profit of RMB 3.961 billion (-41.55%), with Q3 standalone at only RMB 947 million (-69.34%), marks a rare quarterly low since listing. The triple squeeze is clearly identifiable: ① average selling price for the first three quarters of RMB 380.30/MWh and Q3 standalone of RMB 360.23, declining quarter by quarter — the dual impact of lower 2026 annual long-term contract prices and full market entry of renewables (Document No. 136) concentrated in Q3; ② higher fuel costs YoY (H1 delivered benchmark coal RMB 836.84/ton, +0.64%; Q4 spot broke RMB 1,000 but the 99% long-term contract share limited pass-through); ③ associate investment income of RMB 787 million (-54%). Minority interest income of RMB 3.183 billion consumed 44.6% of consolidated net profit, amplifying the attributable decline. Operating cash flow of RMB 37.65 billion (-12.0%) still far exceeded net profit; capex of RMB 25.43 billion narrowed 22% YoY; free cash flow turned positive. Against sell-side consensus (implying Q4 standalone of RMB 2.1 billion for the full year): we believe a Q4 attributable profit of RMB 0.8–1.3 billion is more likely given Q4 tariffs of RMB 355–365/MWh plus winter peak fuel costs, with the full year at RMB 4.76–5.26 billion — the post-Q3 expectation revision is not yet complete ("sell-side estimates flat over the past 90 days" reflects a lagging pre-disclosure state).
Business model: Asset-heavy power generation and operations—controlled installed capacity of 132.02 GW (thermal 63%/hydro 14%/wind 8%/solar 15%), revenue from electricity sales, with market-based trading accounting for over 91.7%; no subscription attributes. Capacity pricing (from 2026, the fixed-cost recovery ratio raised to no less than 50%) begins providing quasi-fixed income for coal power. The project-based joint venture structure results in minority shareholders' equity (RMB 77.69 billion) exceeding equity attributable to the parent (RMB 61.27 billion)—this is the key to understanding the company's financial statements.
Cash content of earnings: OCF/consolidated net profit was 3.34 in 2024 and 3.91 in 2025—depreciation is massive (approx. RMB 21.9 billion in 2025) while electricity fee collection is rigid, so the cash content of book profit is extremely high. However, FCF/net profit was -0.15 in 2024 and 0.57 in 2025—expansion-phase capex (RMB 58.1 billion in 2024, RMB 45.8 billion in 2025) absorbed most operating cash flow; from 2025, as the investment peak recedes, FCF turned positive for the first time. In the first three quarters of 2026, OCF was RMB 37.65 billion and capex RMB 25.43 billion, free cash flow +RMB 12.2 billion.
Return on capital: 2025 ROIC approx. 4.13% (calculated in this report from filing data: NOPAT ≈ net profit of RMB 13.73 billion + after-tax finance costs of RMB 4.54 billion; invested capital = interest-bearing debt of RMB 304.3 billion + equity of RMB 138.1 billion)—below typical utility WACC (6–8%), meaning incremental capital under the current asset structure is not generating excess returns. Long-term value creation depends on hydro (net profit of RMB 0.10–0.115 per kWh) and the realization of returns on injected assets, rather than thermal power balance-sheet expansion.
Capex quality: CapEx/depreciation was 2.89 in 2024 and 2.08 in 2025—predominantly growth investment (hydro dams + renewable mega-bases), converging markedly from 2026 (Q1-3 YoY -22%); the company's disclosures do not distinguish maintenance from growth capex. By industry convention, thermal power maintenance capex is roughly 50–60% of depreciation, implying maintenance CapEx of approx. RMB 11–13 billion/year, comfortably covered by OCF of RMB 53.7 billion.
Red flag list: ① Minority shareholders take 45–48% of consolidated net profit (structural, not fraud, but dilutive to the parent); ② 91.46% of fuel purchases come from the controlling shareholder (top five suppliers in the 2025 annual report); ③ approx. RMB 40 billion of funds/financing business flows through the group's finance company/leasing/factoring platforms (at end-2025: finance company deposits of RMB 13.616 billion, financial leases of RMB 12.879 billion, factoring of RMB 13.423 billion). These related-party arrangements are all institutionally constrained (finance company rates follow PBOC standards), but external verifiability is weak.
Track record of statements vs. delivery: partially delivered. ① Capacity commissioning: the 2025 annual report plans 2026 commissioning of thermal 3.45 GW / hydro 3.7965 GW / renewables 6.7727 GW; actual additions in the first three quarters were 4.0755 GW—hydro at 2.78 GW ahead of schedule, renewables at 0.9455 GW only 14% of plan. Under the stance of "renewables: invest only when returns are certain" (2026 interim report), the pace was deliberately slowed—pragmatic in direction, but annual targets will likely be missed. ② The controlling shareholder's 2018 non-compete commitment (the company as the group's conventional energy integration platform): eight years of slow progress; on 2026-08-20 the first batch of acquisitions finally launched (7 companies, 13.54 GW under construction/planned)—the pipeline is open but not yet closed. Overall verdict: pragmatic but slow-paced.
Shareholder friendliness: shareholder-friendly. Payout ratio: 50.9% in 2023 → 36.3% in 2024 → 60.02% in 2025; the 2025–2027 plan commits to a dual floor of "payout ratio no less than 60% and DPS no less than RMB 0.22," plus a retained-earnings top-up mechanism. 2025 DPS was RMB 0.241, total RMB 4.298 billion; an interim dividend was paid (RMB 0.10 for 2025 interim). No equity refinancing or buybacks in the past three years; expansion funded by debt plus minority contributions at subsidiary level. Note: cumulative dividends of RMB 10.006 billion over the past three years equal 132.8% of the three-year average net profit—the high payout partially draws on historical retained earnings.
Risk signals: ① Chairman Tang Jian resigned in December 2025 (job reassignment); succession arrangements are sparsely disclosed; ② when investors questioned the sharp Q4 2025 profit decline, the company replied only "see the annual report"—insufficient disclosure transparency; ③ on the 2026–2030 capacity structure plan, the company replied it is "still being formulated"—absence of strategic target disclosure.
| Segment (2025 FY) | Revenue share | Gross margin | Revenue YoY | Segment net profit | One-line business logic |
|---|---|---|---|---|---|
| Thermal power | 84.4% | 11.21% | -6.26% | RMB 9.823 billion (approx. 72% of total segment profit) | Mostly coal units; weak fuel-cost pass-through, market-priced electricity, capacity pricing adds quasi-fixed income |
| Hydro power | 7.0% | 46.67% | -7.34% | RMB 2.142 billion | Dadu River/Kaidu River cascade; high-margin cash cow; midpoint rises after Shuangjiangkou commissioning |
| Renewable power | 8.7% | 32.90% | +19.45% | RMB 2.255 billion | Wind/solar mega-bases + distributed; prices under pressure after full market entry under Document No. 136 (2026H1 renewables' parent-attributable approx. -45%) |
The profit engine is thermal, rather than the "thermal dominance" implied by revenue share—thermal contributed 72% of segment net profit on 84.4% of revenue, but its 11.2% gross margin trails hydro's 46.7% and renewables' 32.9% by 20–35 percentage points: hydro's low marginal cost and scarce dispatchability (Shuangjiangkou's annual regulation) make it the group's highest-quality profit asset—hence the market's premium for "hydro growth." Structural changes to watch: renewables have been scaling rapidly (revenue +19.5%) but from 2026, under Document No. 136, they degrade from "fixed-price assets" to "market-priced assets," with rising earnings volatility; thermal profit is highly tied to the coal price–electricity price scissors gap. 2026 H1 data confirms: hydro parent-attributable +22%, renewables -45%, thermal sustaining per-kWh net profit of 2.3 fen (down only 0.6 fen YoY) on 99% long-term contract coal.
Accounting red flags:
Cross-period consistency:
Current market data (close of 2026-10-28): share price RMB 5.26, market cap RMB 93.8 billion. PB 1.53x (56th percentile over 3 years / 61st over 5 years / 80th over 10 years); PE (TTM) 21.6x—TTM parent-attributable profit of RMB 4.35 billion is in a profit downturn, so this percentile is distorted and for context only; PE (2025 static) 13.1x (35th percentile over 5 years); 2027E forward PE approx. 12.5x (sell-side basis). Dividend yield: 2025 DPS of RMB 0.241 implies 4.58%; the committed floor of RMB 0.22 implies 4.18%.
| Peer comparison (2026-10-28) | PE (TTM) | PB | 2026 results | Key differentiator |
|---|---|---|---|---|
| GD Power | 21.6 (distorted) / 13.1 (static) | 1.53 | Q1-3 parent-attributable -41.6% | Coal-power integration + Dadu River hydro + acquisition pipeline |
| Huaneng Power International | 15.7 (static 8.1) | 1.76 | Q1-3 parent-attributable -47.3% | Largest thermal fleet, high market-coal exposure, no large hydro |
| Huadian Power International | 11.2 | 1.19 | H1 parent-attributable -20.5% | Pure thermal comparator, 2026E PE approx. 10.3x (Sinolink, 2026-08-28) |
| Datang International Power Generation | 10.9 | 2.41 | H1 parent-attributable +20.3% | Hydro's counter-cyclical resilience validates the ballast thesis; PB at historical highs |
| China Power (H) | 17.7 | 0.69 | H1 parent-attributable -50.8% | High-purity green power, hit first by Document No. 136 |
(Note: Huaneng's 5.3% dividend yield is per Huatai's 2026-03-25 basis; other peers' dividend yields unavailable; PB calculated in this report from 2026-10-28 closing data.)
Market-implied expectations: reverse-solving the current RMB 93.8 billion market cap at an 8.5% cost of equity implies sustainable parent-attributable cash flow of approx. RMB 8 billion/year—in one sentence: the current price requires the company to deliver and sustain approx. RMB 7.5–8.0 billion of parent-attributable profit in 2027, while the 2026 reality is RMB 4.76–5.26 billion—the gap hinges on two unconfirmed variables: December long-term contract negotiations and hydro commissioning. This implied expectation is partially backed by real construction in progress (Shuangjiangkou impoundment, Danba approval, launch of the 13.54 GW acquisition)—not pure narrative—but is roughly 12–19% above our base case (RMB 6.7 billion).
Three-tier value (EPV): book asset value RMB 3.44/share (rough replacement-cost estimate RMB 4.7–5.8, including Dadu River scarcity but with minority shareholders taking the lion's share—not realizable value); zero-growth EPV RMB 3.63/share (normalized parent-attributable profit of RMB 5.5 billion—taking the 2023–2025 adjusted mean of RMB 5.44 billion and balancing capacity base growth against tariff midpoint decline—divided by 8.5% cost of equity; sensitivity: RMB 3.17 at the 2026E midpoint of RMB 4.8 billion, RMB 3.96 at RMB 6.0 billion); the current price is approx. 45% above zero-growth value, with the growth option representing approx. 31% of the price (EPV inputs: equity basis, normalized cash flow/share RMB 0.308, discount rate 8.5%)—the market pays approx. RMB 1.63/share for "hydro + asset injection," a non-trivial share of the price, whose realization depends on the 2027–2030 commissioning schedule and contributes little within a 12–18 month window. The three tiers are not additive: EPV + growth option = current price, with asset value serving as an independent floor reference.
Three scenarios and odds (12–18 months):
| Scenario | Probability | 2027E parent-attributable | Fair value range (midpoint) | vs. current price | Decisive factors |
|---|---|---|---|---|---|
| Bear | 30% | RMB 5.5–6.0 bn | RMB 3.7–4.2 (3.95) | -24.9% | 2027 long-term contracts cut another 1–2 fen + standard coal holding at RMB 850 + dry hydro; the RMB 0.22 dividend floor would require a 68%+ payout ratio to sustain |
| Base | 50% | RMB 6.2–7.2 bn (6.7) | RMB 4.9–5.4 (5.15) | -2.1% | Tariff recovery of 0.3–0.5 fen + Shuangjiangkou full-year annualization + standard coal falling to RMB 800–830; PE 12.4×RMB 6.7 bn, PB 1.45×3.60, DPS 0.225/4.4% triple-anchor cross-check |
| Bull | 20% | RMB 8.5–9.0 bn | RMB 6.3–7.0 (6.65) | +26.4% | Thousand-yuan coal driving contract price pass-through + wet hydro + rapid acquisition consolidation; DPS upgradeable to RMB 0.26+; benchmark Guotai Haitong target price RMB 6.44 (14x 2027 PE) |
Probability-weighted fair value is approx. RMB 5.09, -3.2% vs. current price—the odds are roughly symmetric, slightly skewed to the downside. Base-case exit multiple anchors: the PE anchor takes Huadian Power's 2026E of approx. 10.3x plus a hydro/dividend premium of approx. 20% (yielding 12.4x), cross-checked against the company's own 5-year static PE median of 13.1x and sell-side implied 12.5x—three independent anchors; the PB anchor takes the four-peer median of 1.48x; the dividend anchor takes 4.4% (midpoint of required return for dividend assets). For the bear case, no institution-grade bearish target price comparable to the post-Q3 period was available (sell-side 2026E has been cut from RMB 7.27–7.90 bn in August 2025 to RMB 6.064 bn—approx. 20% over 14 months; the downward revision trajectory itself is a bear-case reference); the bull case references Guotai Haitong's RMB 6.44 (its 2026E of RMB 8.0 bn is 32% above consensus, with possibly outdated coal price assumptions—for coordinates only).
Our own earnings forecast (reconciliation anchor):
| Period | Revenue | Parent-attributable net profit | Core driver assumptions |
|---|---|---|---|
| 2026E | RMB 168–172 bn | RMB 4.76–5.26 bn | Tariff RMB 355–365/MWh in Q4; Q4 parent-attributable RMB 0.8–1.3 bn (tax structure partially normalizing); impairment convergence continuing |
| 2027E | RMB 172–178 bn | RMB 6.2–7.2 bn (midpoint 6.7) | Tariff recovery of 0.3–0.5 fen; Shuangjiangkou full-year annualization + increased downstream output; standard coal RMB 800–830; associates stabilizing |
Management gave no quantitative guidance; sell-side consensus is 2026E RMB 6.064 bn / 2027E RMB 7.491 bn—ours is 13–21% lower for 2026E and approx. 10% lower for 2027E, with the divergence mainly in the magnitude of tariff recovery and Q4 cost pacing.
Conclusion: Fair. Quality (SOE platform + integrated costs + hydro growth + dividend commitment) and price (median PB, implied expectations partially front-run) are broadly balanced: the current price is approx. 2% above the base-case fair midpoint and approx. 3% above the weighted fair value—within the fair range, neither cheap nor bubbly. Suitable for dividend-oriented capital to hold and await validation; not a high-odds entry point. The December long-term contract outcome will be the direction-deciding event.
Industry size: In 2025, total electricity consumption reached 10,368.2 TWh (+5.0%), breaking the 10-trillion-kWh threshold for the first time—roughly 2x annual U.S. electricity consumption. National installed generation capacity reached approximately 3.9 billion kW, with non-fossil capacity accounting for ~61% (China Electricity Council, Annual Development Report of China's Power Industry 2026, July 2026). Growth rates: +6.8% in 2024, +5.0% in 2025, and an average annual +6.6% during the 14th Five-Year Plan period. The CEC forecasts +5–6% power consumption growth in 2026, ~400 million kW of new capacity additions, and year-end installed capacity of 4.3 billion kW; by 2030, total electricity consumption will exceed 13,000 TWh (implying an average annual growth of ~5% during the 15th Five-Year Plan period). The strongest exogenous incremental growth comes from computing power and electrification: per NEA data, data center electricity consumption exceeded 400 TWh in 2025 (4.2% of total consumption); State Grid Energy Research Institute estimates it could reach 800 TWh by 2030 (6–7% of the total, with a 2025–2030 CAGR of ~14.9%). High-frequency data corroborate this: from January to August 2026, electricity consumption by internet data services grew +42.5%, battery charging/swapping services +55.1%, and high-tech & equipment manufacturing +7.2% in August alone. AI demand is a "moderate accelerator" rather than an explosive inflection point for the power sector: data centers account for ~15% of incremental electricity consumption during the 15th Five-Year Plan period, contributing ~0.8 percentage points to average annual growth. GD Power has no direct "computing-power synergy" asset positioning; its benefit pathway is indirect (peak-shaving tariffs and utilization hours in eastern regions + premium potential for Dadu River green power under the "East Data, West Computing" green power requirements).
Value chain and value distribution: Upstream coal (fuel costs account for 60–70% of thermal power operating costs; reasonable long-term contract price band: RMB 570–770/ton) → midstream generation operations (where the Company sits, with controlled capacity of 127 million kW at end-2025, ~3.2% of national total and 5.3% of national thermal power) → downstream grid procurement + market-based trading (primarily commercial & industrial). The tariff mechanism is undergoing a three-layer restructuring: ① Energy tariff (coal benchmark price ±20%), with 2026 annual long-term contracts down 3–8% across provinces; ② Capacity tariff (Document No. 1501), raising the recovery ratio of coal power fixed costs from 30% to no less than 50% starting 2026 (~RMB 165/kW·year), evolving the thermal power business model toward a hybrid "cyclical + utility" framework; ③ Ancillary services / spot market peak-valley spreads, with spot markets largely in formal operation by 2027 and market-based electricity reaching ~70% of total consumption by 2030 (State Council General Office's February 2026 unified power market opinion). Bargaining power over upstream: backed by China Energy Group, the world's largest coal company, GD Power's long-term contract coal ratio was 99% in 2026H1, delivering a significant cost advantage during coal price upcycles (2026H1 as-fired standard coal price +0.64% vs. market coal +13%+); downstream, it is a price taker, with profit stabilization shifting to capacity tariffs + flexible generation assets.
Supply-demand and competitive landscape: Capacity-based CR5 of ~37–38%—the Big Five power groups totaled ~1.47 billion kW at end-2025 (China Energy Group 396 million kW leading, Huaneng 300 million, Huadian 281 million, SPIC 280 million, Datang 214 million). Entry barriers are extremely high (project approval quotas + massive capital requirements + trading capability + coal resources). Marginal competitive shifts: ① Renewables are shifting from capacity expansion to curtailment and pricing—national wind utilization was 91.5% and solar 90.8% in January–February 2026, with many provinces breaching the 90% red line; after Document No. 136 pushed full market entry, the bidding cap for mechanism tariffs on incremental projects fell to as low as RMB 0.32/kWh (Tianjin implementation plan, October 2026); ② Clear contraction in thermal supply—only 32 GW of coal power was approved nationwide in 2025 (Guangdong only 0.56 GW); new thermal additions will fall sharply from 2027, with supply-demand reversal expectations supporting tariff recovery; ③ 2026 coal price reversal (spot RMB 1,021/ton vs. long-term contract RMB 717/ton) is reshaping industry profit distribution, making long-term contract coverage the dividing line among thermal operators. 2026H1 net profit of the A-share thermal power sector fell ~-21% YoY, with 22 of 33 listed power SOEs declining, amid regional divergence (coastal regions under pressure, inland long-term contract benefit zones bucking the trend).
Cycle and regulation: The industry's profitability is at the stage of "thermal downturn bottoming out, tariff inflection brewing"—the sharp coal price drop in 2025 created a bumper year for thermal profits (Big Five flagships' combined net profit of RMB 38.4 billion, a record), while 2026 faces reversal pressure from coal prices +13.9% and broad tariff declines. Leading indicators: ① Qinhuangdao spot prices of RMB 1,013/1,026 per ton on October 13/19, returning above RMB 1,000 for the first time in three years (NDRC has conducted interviews and supervision); ② Monthly/spot tariffs turning YoY positive since September (Guangdong +RMB 84.4/MWh in October, Jiangsu +RMB 54.6)—Guangdong comprehensive tariffs +8.3% YoY in September 2026, Jiangsu average bidding price +7.8%; ③ 2027 annual long-term contract negotiations (December). Regulatory direction: institutionalized capacity tariff compensation for flexible generation; Document No. 136 bringing renewables fully into the market (first-year stress test passed: grid-connected renewable energy volume in State Grid regions +6.9%, tariffs broadly stable); the New Power System "15th Five-Year Plan" targeting non-fossil generation at 50% of output and 410 million kW of conventional hydropower by 2030. Overall: neutral with structural benefits favoring integrated operators with rising coal-power integration + hydro share (the GD Power model).
Company's industry positioning: China Energy Group's flagship platform for conventional energy integration, in the top tier of integrated operators (revenue/net profit second only to Huaneng Power), with profit resilience among the industry's best in 2026 (per-kWh thermal net profit fell only 0.06 cents to 2.3 cents amid the coal price rebound, while peers generally saw double-digit declines). Share trend: capacity growth faster than the industry (2025 +13.5% vs. national +16% total capacity, but the company's thermal capacity +5.3% faster than national thermal's 3%+), plus the group's pipeline of 70GW+ unlisted conventional energy reserves—market share stable with an upward bias. Moats: ① Coal-power integration (group coal self-sufficiency + 99% long-term contracts); ② Dadu River full-basin cascade + Shuangjiangkou annual-regulation master reservoir (scarce flexible assets); ③ SOE credit and low financing costs (super short-term commercial paper rates of 1.41–1.60%). Market share note: the company's capacity is ~3.2% of the national total (estimated from CEC national data), with no third-party ranking disputes.
This is the four-factor decomposition for power operators, and also the framework for understanding the company's profit trajectory over the next two years (capacity × utilization hours × on-grid tariff − fuel cost).
Installed capacity (controlled basis, 10,000 kW):
| Point in time | Thermal | Hydro | Wind | Solar | Total |
|---|---|---|---|---|---|
| End-2023 | — | — | — | — | 10,558 |
| End-2024 | 7,463 | 1,495 | 984 | 1,228 | 11,170 |
| End-2025 | 8,227 | 1,513 | 1,050 | 1,889 | 12,679 |
| End-2026Q3 | 8,302 | 1,797 | 1,070 | 2,033 | 13,202 |
Net addition over two years of ~26.45 million kW (+25%), of which renewables contributed ~11.2 million kW, hydro 3.02 million kW, and thermal 8.4 million kW; new additions in the first three quarters of 2026 were 4.0755 million kW (hydro 2.78 million, with most of the target completed early; renewables 0.9455 million, only 14% of the annual plan). Under construction: hydro 5.6665 million kW (Shuangjiangkou Phase I 1.5 million kW commissioned; 4th unit Q4–2027H1) + proposed acquisition of the group's 13.54 million kW of under-construction/planned projects.
Utilization hours: 4,511 (2023) → 4,301 (2024) → 3,906 (2025) → 1,715 in 2026H1 (−46)—the three consecutive declines are mainly due to dilution from renewable capacity additions and wind/solar crowding out (national coal power utilization hours at 3,269 in 2025, −199), compounded by reduced hydro output in 2025. The company's thermal utilization hours of 4,781 (2025) remain significantly above the national coal power average; guaranteed dispatch volume from coal-power integration and top-tier peaking capability are structural advantages. 2026Q3 thermal generation −5.73% (double-digit declines in many provinces), hydro +19.09% (abundant water inflow + new units).
On-grid tariff and marketization: Average on-grid tariff 437.78 → 429.82 → 400.90 → 380.30 RMB/MWh (2026Q1–3), with Q3's single-quarter 360.23 RMB marking a multi-year low—with market-based trading above 91.7%, the company's tariff essentially tracks the market; coal units traded at a premium of 11.73% over the benchmark in 2025 (19.29% in 2024), and the narrowing premium is the direct source of margin compression. From 2026, capacity tariff recovery at ≥50% provides partial offset (coal power 83.02 million kW × ~RMB 165/kW·year ≈ RMB 13–14 billion capacity fee revenue base, of which the incremental fixed-cost recovery portion is pure profit improvement, not separately disclosed).
Fuel cost: As-fired standard coal price 934.96 → 922.17 → 825.06 → 836.84 RMB/ton (2026H1, +0.64%)—long-term contract share rose from 94% → 97.73% → 99%, with 188 million tons of raw coal purchased in 2025, 184 million tons under long-term contracts; with spot prices breaking RMB 1,000 in October, the company's cost exposure hinges on 2027 long-term contract coal policy (NDRC notice in November) and related-party procurement pricing (91.46% from the group). Sensitivity: each +RMB 10/ton in as-fired standard coal ≈ −RMB 470 million to net profit attributable to parent; a 5% overall premium on long-term contracts ≈ −RMB 1.9 billion.
Unit economics: Thermal per-kWh net profit 2.83 cents (2025) → 2.3 cents (2026H1); Dadu River per-kWh net profit ~RMB 0.10–0.115 (2026Q2 actual)—hydro per-kWh profitability is 4–5x thermal; once Shuangjiangkou reaches full annualization, the hydro segment's profit center will climb toward RMB 2.5–3.0 billion (2026H1 hydro net profit attributable to parent RMB 1.081 billion, +22%). Renewable subsidy receivables (portfolio basis, mainly electricity fees) stood at RMB 29.521 billion at end-2026H1, with bad debt provisions of RMB 2.392 billion (8.10%); individual subsidies of RMB 631 million have been fully provided for—subsidy collection cycles are an industry-wide issue, and the company's provisions are on an upward trajectory.
Overall rating: Neutral (confidence 0.55, 12–18 months). The balance between quality and price: the company offers a scarce combination of coal-power integration + Dadu River hydro + group asset injection pipeline, with a 60% payout ratio in 2025 and a guaranteed DPS commitment of RMB 0.22 (current dividend yield 4.18–4.58%); however, the current price already requires near-full realization of the 2027 recovery (implied ~RMB 7.5–8.0 billion attributable net profit vs. our base case of RMB 6.7 billion), with odds skewed to the downside and no margin of safety. Strategy: holders should treat dividends as baseline returns and wait for December validation; incremental capital need not chase—the lower bound of the base-case fair range of RMB 4.9–5.4 (~RMB 4.9, corresponding to 1.43x PB and 4.5% dividend yield) is a better entry point.
Key risks: ① Further decline in 2027 long-term contract tariffs (each RMB 0.01/kWh ≈ −RMB 1.2–1.5 billion attributable)—in the bear scenario, the share price reverts toward RMB 3.7–4.2 (−25%); ② Long-term contract coal policy premium or lower fulfillment (+RMB 50/ton ≈ −RMB 1.9–2.3 billion attributable); ③ Q4 results below our forecast (impairments or tax structure recurrence); ④ High acquisition premium + subsequent capex becoming a burden (debt-to-asset ratio of 73.55% rising further); ⑤ Dry hydrology erasing hydro upside (−10% ≈ −RMB 500–600 million attributable).
Catalysts and monitoring calendar:
Falsification conditions: ① 2026 annual report attributable net profit < RMB 4.4 billion or > RMB 5.6 billion (revising the C1 forecast framework); ② Guangdong 2027 annual long-term contract < RMB 0.372/kWh with key provinces falling another ≥1 cent (falsifies the C2 recovery narrative); ③ 2026 DPS < RMB 0.22 (dividend commitment broken, invalidating the dividend valuation anchor); ④ Share price breaks below RMB 4.4 (bear scenario realized, re-evaluation); ⑤ Share price breaks above RMB 5.4 (upper bound of base-case fair value, margin of safety exhausted, entering profit-taking assessment zone).
Report date: 2026-10-29 | The price anchor for this report is the 2026-10-28 closing price of RMB 5.26; all valuation calculations are based on data as of that date; multiples and percentile figures are computed on the 2026-10-28 close. This report does not constitute investment advice.