What do we expect over the next 12 months?

Overall power demand growth to stabilize at a mid-single-digit (certain countries could see 7%), above world average.  Asia is set to use half of the world's electricity by 2025, with China accounting for one-third of the global total. We forecast China's real GDP will expand by 4.4% in 2024, while a few other countries, including India, will see high growth of 6%-7%. Residential demand growth will outpace that of industrial demand, despite the latter still accounting for nearly half of Asia-Pacific's total consumption.

Natural gas demand is recovering to be in line with that of overall power consumption over the next two years.  This will underpin the profitability of gas distributors. Industrial demand and normalizing gas prices are driving the increase. While gas meets supply security needs and is a transitional energy for climate-related targets in Asia Pacific, its penetration in the energy mix varies widely based on resource availability and affordability.

Easing fuel costs and increasing renewable generation will underpin operating cash flow, despite overhanging geopolitical risk.  Pass-through remains uneven due to varied regulatory frameworks among countries, but easing thermal coal and gas prices, plus more renewable power consumption, will aid earnings recoveries. Our current base case expects the war in the Middle East will have limited economic and credit impact outside that region. But if geopolitical risks heightened further, this could disrupt energy supplies, causing price volatility.

Leverage will stay high, mainly due to debt-funded investments to meet energy transition goals.  China and India are leading the growth in power demand and investments. Besides low-cost renewables, both countries also continue to add coal-fired generation capacity, mainly to ensure supply amid demand growth. In some other countries, potential mergers and acquisitions (M&A) and upstream/downstream expansions could also add pressure to metrics.

What are the key risks around the baseline?

Downside risk on demand growth.  Economic slowdown in the region, if more than expected, could directly dampen the momentum for power and gas demand. A failure to stabilize China's prolonged property downturn would hold back country's overall economic recovery (see "China Growth Could Fall Below 3% If The Property Crisis Worsens," published on RatingsDirect on Oct. 23, 2023). This is particularly at a time when weak global demand is already weighing on exports.

More volatile fuel prices than expected.  Escalation of geopolitical tensions could disrupt energy supply, pushing up prices. That said, long-term procurement contracts or price regulation in some markets partially mitigate spot price volatility, depending on companies' exposure to spot prices.

Higher interest rates and inflation remain key risks in some markets.  If escalation of geopolitical tension triggers energy-price spikes, a new wave of inflation could rise even when the current one hasn't yet subsided. The credit impact will depend on the effectiveness of interest cost pass-through and the intensity of funding needs for growth or refinancing. Inflation-linked pricing and the regular tariff adjustments allowed in some markets can help mitigate the risk.

Overaggressive expansion of unregulated businesses.  This could heighten the business risk and dampen the overall cost pass-through if there is a lack of longer-term protections. Market-based reforms in the energy sector is likely to increase volatility of power prices and utilities' earnings.

Adverse regulatory reforms or government interventions.  This could mainly affect some less-developed markets with less regulatory stability. Affordability considerations could result in government interventions to delay cost recovery and hurt revenue protection.

Australia and New Zealand: Uphill Investment Task

What are the key risks on the baseline? What do they mean for the sector?

AUSTRALIAN AND NEW ZEALAND REGULATED UTILITIES 

Inflation benefits to revenues could be partly offset by cost side pressures.  Inflation-linked pricing will flow to revenues, but margins will be suppressed by higher labor, contract and procurement costs. In New Zealand, an annual cap to price increases can also constrain margins. Refinancing of debt will increase interest costs, mitigated somewhat by the annual adjustment to debt costs, or higher weighted average of cost of capital where pricing resets are due. Softer gas demand or new connections could limit upside to gas distributors.

Outperformance of regulatory allowances can be harder.   Inflationary pressure on project maintenance costs will reduce cash available for distributions. We view this risk as manageable because shareholders of most of the rated entities are long-term infrastructure investors. Hence, they are less likely to extract cash.

An accelerated pursuit of growth in the unregulated segment will bring risks.  Rapid growth in renewable power and demand for electric vehicle (EV) charging infrastructure will demand large investments. Most of these are likely to be contracted or unregulated, and be debt-funded. We expect phased growth; however, a rapid increase in unregulated investments could dilute our assessment on business risk.

AUSTRALIAN UNREGULATED UTILITIES  

More renewable power heightens risk to coal plants. This known risk is escalating due to lower average prices of renewables amid an increase in roof-top and large-scale solar.  Still, stability and reliability issues, as well as uncertain visibility on the roll-out of renewable capacity, is leading to life extensions for some coal plants. Volatile pool prices, plant availability and construction costs remain the biggest risk to the unregulated sector over the next one to two years. Lifting retail price caps will provide some respite for those with plant portfolios.

Substantial investments to add renewable power present mixed outcomes.  Construction costs, approvals, network connections and contract arrangements will be steady variables and risk to project deliveries. Planned investments for generation and transmission are substantial, spurred by the target to reduce emissions by 43% by 2030.

NEW ZEALAND UNREGULATED UTILITIES 

Merchant utilities gearing up for several new "green" projects.  Cost management and execution remain key risks amid tight supply of contractors and long lead times for equipment supply. While some projects have been completed recently with no or limited risk to credit quality, others have seen cost escalation or delays due to weather, supply, or design changes.

We forecast that electricity prices will remain high based on normal hydrology and stable demand.  Downside risks include extreme hydrology, reduced demand by the aluminum smelter or a slow rise in alternate demand, and strong retail competition.

Rating headroom provides some cover for unexpected movements.  Most rated entities have ample headroom to withstand cash flow volatility. Prudent policies on shareholder distributions are back and likely to stay in place during the upcoming building phase.

South and Southeast Asia: Growing Pains in Energy Transition

What are the key risks for the baseline? What do they mean for the sector?

REGULATED UTILITIES 

Weaker performance for renewables will weigh on leverage.  Continued underperformance below P90 (meeting power generation probability at least 90% of the time) will strain cash flow and margins. Resource risk is greater for players more exposed to wind assets, such as in India and Indonesia, where performance recovery has been lagging. Lower cash flow and aggressive growth spending will likely keep leverage high, with debt-to-EBITDA ratios over 6.0x.

Robust regulations can accommodate higher costs.  This and timely tariff resets in India and Singapore allow utilities to pass on higher interest costs to end consumers, protecting cash flows. Moderating fuel costs from last year's peaks can provide some relief to generation and distribution firms that face a lag in recovery. Higher operating costs (for some countries) may bite into margins.

Reversal to pre-pandemic regulatory tariff frameworks for most countries, except Thailand.  South and Southeast Asia able to or are beginning to recover tariffs deferred during the pandemic. Many have reverted to pre-pandemic regulatory frameworks and tariff mechanisms. However, the Thai government retained some relief measures this year and approved a tariff cut from September to December 2023. A watchpoint is whether Thailand will stick with its tariff philosophy of regulated returns with full cost pass-through.

UNREGULATED UTILITIES  

Rising interest costs and inflation remain key risks.  Unregulated power players are exposed given they are unable to pass on increases in such costs. Companies that require large funding needs for growth or refinancing may be more vulnerable. While fuel costs have eased, generation companies will be exposed to fuel price fluctuations if they have fixed-price contracts. In some markets, such as Philippines, power purchase agreements were cancelled and contracts renegotiated to allow for fuel cost pass through. Nevertheless, most of our rated independent power producers (IPPs) in Thailand and Indonesia can pass through fuel costs under existing contracts.

Growth investments in overseas markets can be a double-edged sword.  Many IPPs are investing opportunistically in offshore markets to increase scale and enhance geographic diversity. Some of the plans may be driven by energy transition. However, sizable debt-funded investments can pressure balance sheets and elevate leverage. Earning quality can suffer if exposures rise in countries that carry higher regulatory and country risks, such as Vietnam and Laos.

Cash flows could be more volatile due to increasing exposure to merchant power markets.  More power producers, for example in the Philippines, are expanding into merchant power markets. This strategy offers higher returns at the expense of higher risk via more exposure to spot-price volatility. Mitigants to such volatility range from active trading strategies to long-term contracts which offer downside protection to the floor price during lower pricing-power conditions. The ability to weather depressed power price periods or unforeseen detrimental circumstances will depend on sponsors' financial discipline.

Greater China: Heavy Investments May Eclipse Modest Margin Recovery

What are the key risks around the baseline? What do they mean for the sector?

Power demand growth slowdown may hurt utilization hours for China's IPPs.  China's power demand growth will likely soften to 4%-5% in 2024 as sluggish property and export-related sectors depress industrial production. Coal-fired power will be the most affected because the rapid renewable energy deployment is eating into its share. Meanwhile, coal units will gradually assume the role of peak shaving in the power system. This is because the lack of storage facilities for intermittent power output of wind and solar makes it inflexible to match the power demand curve. Additional revenues from such ancillary services may not fully compensate for the loss of utilization hours by the coal fleets.

Coal power tariffs may start to soften in 2024 as thermal coal prices normalize.  IPPs sell most of their power through annual contracts that lock in tariffs for the full year. As such, recent weaknesses in the spot market will not materially affect their overall tariff level for 2023. Nevertheless, we expect power tariffs to start edging down in 2024 since the annual contracts signed for the next year may factor in potential coal price declines. Loosening power supply-demand in China may also contribute to price weaknesses.

China's ambitious energy transition plan will load state-owned IPPs with even more debt.  IPPs will invest heavily in renewables over the next couple of years as COVID-related lockdowns in the previous two years have slowed the progress of clean energy development. Heavy debt-funded capex may weigh on the credit improvements brought about by declining coal costs. Plus, competition over new renewable projects is keen, and the additional costs of installing energy storage may also narrow new project returns.

Hong Kong: Upcoming five-year plan announcement should bring clarity on transition-related spending burdens.  The plan will likely be released by the end of 2023, and guides the power companies' capex over 2024-2028. Energy transition will be the key theme and may entail development of offshore wind farms and upgrades of the existing power grids to accommodate a higher mix of renewables.

Transmission capabilities between Hong Kong and mainland China will also be strengthened to import more clean energy directly from the mainland. The regulatory framework will likely remain strong and ensure steady profits for the power companies. Cash flows should improve because declining fuel costs may help recoup their prior deficits in the Fuel Clause Recovery Accounts.

China gas distributors: Weaker-than-expected volume growth may dampen retail gas earnings.  We project gas volumes will rise by an average 9% annually for rated issuers over the next couple of years. The industrial production slowdown will probably limit the recovery of China's gas consumption. High double-digit growth seen prior to 2022 is thus unlikely for the foreseeable future. Also, the falling mix of high-margin industrial gas sales will drag on distributors' average dollar margins.

Ineffective or delayed cost pass-through would hurt dollar margins.  We expect dollar margins for gas distributors to modestly rise by Chinese renminbi (RMB) 0.01/per cubic meter (cbm) to RMB0.02/cbm in 2024 as pass-through continues to improve in various cities post-pandemic. However, pass-through policy still varies across local governments, particularly in the residential sector, and socioeconomic considerations such as boosting economic growth or ensuring user affordability may influence governments' ultimate decisions in end-user price adjustments.

Price volatility remains for liquified natural gas (LNG).  Gas distributors are diversifying their gas procurement channels to reduce their reliance on the big three oil majors. This includes purchases of unconventional gas and importing LNGs through long-term contracts and spot trading. These currently account for 10%-20% of gas sources for our rated issuers with high project coverage in coastal provinces. Our improving dollar margin forecasts factor in declining LNG costs, in line with the global energy price trend. However, any price jumps caused by demand spikes or supply disruptions will raise the cost base of the distributors.

Taiwan: Large capex for energy transition with stressed profitability due to high cost for renewable energy and domestic LNG prices.  Following the government's energy transition policy, Taiwan Power Co. will invest heavily to expand gas-fired plants, network reliability improvement, and network connections for additional green power. This could weaken debt leverage over the next few years. Meanwhile, domestic LNG prices could remain high in 2023-2024. This as well as rising purchase costs for renewable energy will continue to strain the company's profitability. While the government has twice adjusted tariff upwards to reflect rising fuel costs since July 2022, the increments are still far less than sufficient to cover increasing costs.

Japan, Korea: Earnings Recover; Leverage Remains Elevated

What are the key risks around the baseline? What do they mean for the sector?

ELECTRICITY UTILITIES  

Higher fuel costs.  Fuel prices could spiral if, for example, underlying geopolitical risks accelerate further. This would delay our baseline assumptions that earnings and finances for the industry will recover in 2024.

For Korean utilities, another significant spike in fuel costs would directly hit credit metrics. Delayed and insufficient tariff hikes drove a sharp increase in its debt burden in 2022, and uncertainties around tariff hikes remain high.

However, for Japanese electricity utilities, higher fuel prices won't cause immediate credit stress that occurred over the past two years. This is because the Japanese government approved new pricing formulas in early 2023 that allows the regulated power companies to pass higher fuel costs more easily.

Acceleration in investments.  Free cash flow deficits could further deteriorate due to aggressive investments in decarbonization. This adds to spending on maintenance and replacement of conventional thermal power facilities and, for Japanese electricity utilities, the burden of enhanced safety measures to restart nuclear power plants. This could pose more downside pressure for issuers whose credit metrics have been dampened during the global energy crisis.

For Korean utilities, investment burdens will also likely remain elevated due to construction of nuclear plants and investments in renewable energies.

Intensified competition in domestic electricity retail in Japan.  Full deregulation of electricity retail in 2016 opened the retail market to hundreds of newcomers. Many peers aggressively switched their fee plans to transfer volatility in fuel procurement prices to end customers. This means the industry might face another round of fierce competition as was common until a few years ago. This could subdue profitability for the sector.

GAS SECTOR 

Expansion in unregulated businesses for Japanese gas players.   Japan's leading regulated gas players are aiming at accelerating investments in domestic electricity retailing, renewable energy and overseas businesses like gas upstream projects or IPPs. Profit is more volatile in these businesses than in the regulated domestic gas utility business. Higher exposure to such areas could heighten the volatility of their earnings.

Higher oil and gas prices for Korea Gas (Kogas).  Kogas posted profits on an accounting basis, even amid the high commodity prices in 2021-2022. Yet, significant working capital outflow from higher oil prices led to sizable negative discretionary cash flow and drove a sharp increase in debt. Resurgence of oil and gas prices, if any, could lead to an increase in working capital burdens and another upward turn in debt.

Difficulties in timely tariff adjustments for Kogas.  Due in part to delayed tariff adjustments for general and household use, Kogas' receivables associated with city gas rose to Korean won (KRW) 12.7 trillion in June 2023 from KRW2.2 trillion in 2021. We estimate it would take five years or more for Kogas to recover the receivables. Uncertainties around the timely tariff adjustments remain a key swing to the company's credit metrics and deleveraging efforts.

Digital design: Halie Mustow, Evy Cheung

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