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Low oil prices have now injected more turbulence. For the foreseeable future, the industry will encounter rough seas. The long-term economic fundamen-tals remain sound, but market volatility and low oil prices will make it difficult to embark on new projects. There is some good news: While lower oil prices complicate the supply side, they pro-vide a stimulus to demand. Lower oil-indexed prices could open up the LNG market in key emerging economies and spur efforts to reduce costs. These de-velopments could put the industry on a stronger footing for the long term.

The first big impact created by lower oil prices is very direct — they effec-tively lead to lower LNG prices. Most LNG is sold under long-term contracts, and prices in these contracts are typi-cally linked to the price of oil. So as oil prices fall, LNG prices fall in turn, after a lag of several months and according to pre-agreed formulas. Some contracts in-clude clauses that soften the price drop, but such measures exist in a minority of cases. IHS expects prices to drop con-siderably in 2015 versus last year. For ex-ample, Japan’s weighted average import price for 2015 is projected to be below $10 per million Btu (MMBtu), as opposed to nearly $16 per MMBtu in 2014. Spot LNG prices have already plummeted.

A bright side of lower prices is that they could bring new customers to the LNG market. Oil-indexed con-tracts in recent years have simply proved too expensive for many aspir-ing buyers. Now producers can of-fer the same oil-indexed contracts as before, but with lower oil prices, they will in effect be offering customers lower prices for LNG. The gap between buyer and seller around the negoti-

ating table has narrowed. This could bring in new customers, especially in emerging markets, which are the most price-sensitive. Primary targets include Bangladesh, Egypt, Jamaica, Pakistan, the Philippines, Panama, South Africa and Vietnam, as well as upside in the existing market of India. The catch is that oil prices will need to remain both low enough in the future to support this demand, and also high enough to sup-port new project investments. To make inroads in emerging economies that are less credit-worthy, LNG developers may also need to support buyers by in-vesting in their downstream infrastruc-ture and, critically, by providing forms of credit support.

Despite the current low oil prices, most LNG projects remain economical-ly robust over the long term. IHS Energy has calculated the oil-price thresholds required to cover life-cycle costs and provide an appropriate return for LNG projects. A typical greenfield project — for example in East Africa or Western Canada — requires a “free-on-board” (FOB) price of around $10-12 per MMBtu. With pricing at the historically normal ratio to oil, such projects would require oil prices in the range of $70-82 per barrel to break even. This is within the range of most anticipated long-term oil prices.

To take advantage of current oppor-tunities and to enhance the long-term competitiveness of LNG, developers must reduce costs. There are a host of options. Many developers are promot-ing miniaturization: smaller-scale proj-ects that hope to achieve lower unit costs and reduced project complex-ity. Modularization — fabricating key components in low-cost regions and

assembling on-site — is another prom-ising avenue for cost reduction. This can be done even with large-scale projects made up of a number of smaller units. Standardization is another option (see related article in this special section on standardization as a tool for cutting costs in oil exploration and production). Cost savings can also be achieved by reducing the local content that is often required by resource-holding govern-ments. Such provisions were common when oil prices were high, but they can be carried too far and end up add-ing costs and/or delaying projects, af-fecting the competitiveness of projects. The kind of local content requirements imposed in an era of high prices will re-quire revisiting in light of current prices.

The threat to new LNG projects is less economic and more financial. Short-term price swings ought not to have strong impact on new investments that will require five or 10 years to come on-line, but in fact, prices today do matter. Critically, terms in LNG contracts have reflected the status of the market at the time of negotiation, not the time of de-livery. Given that, today’s weak market means any contract signed today will involve weaker terms for sellers.

Companies will generally find it dif-ficult to invest against the current cycle, especially at a time when capital bud-gets are being slashed. LNG projects, especially traditional integrated inter-national projects, risk being cut if they rank at the low end of a company’s proj-ect list in their internal rate of return or if they are at the high end as a draw on capital. Those in the early stages could very well end up being postponed for an indefinite period of time.

Some of the strongest and largest

companies may continue to invest against the cycle. A prominent prior example is the go-ahead decision on Gorgon LNG made in 2009 after the oil price crash that followed the 2008 finan-cial crisis. Gorgon’s partners were finan-cially strong and willing to look beyond the immediate horizon. But most LNG projects involve complex consortia that move at the pace of the slowest or weak-est partner. Few projects are likely to have partners all able to operate free of current constraints.

National oil companies (NOCs) of importing countries like China, India, Japan and Thailand will have an op-portunity to acquire and develop LNG for their domestic market at attractive terms and may partially be able to fill the gap created by reduced activity on the part of international oil companies (IOCs). But NOCs often lack the critical operating experience, which poses an additional set of challenges.

So will LNG continue to play a ma-jor role in the future? Despite current challenges, the answer is an unequiv-ocal “yes.” Given the abundance of gas resources in the portfolios of industry players, there are strong in-centives — and a need — to ensure continued LNG development. And LNG will continue to offer an attrac-tive clean-energy source. Low oil prices have created turbulence but could also create the requisite pressure to drive innovations that open up new mar-kets and reduce costs. The prospect of those efforts coming to fruition is the silver lining amid the storm clouds the LNG industry is now encountering.

Michael Stoppard is Chief Strategist, Global Gas at IHS Energy.

Even before oil prices began to fall last year, the liquefied natural gas (LNG) industry faced significant challenges. The first was a shortage of demand, at least when measured against prospective supply. Although demand is expected to grow strongly, the number of proposed projects still far exceeded the needs of likely customers. The second was spiraling costs. The IHS Upstream Capital Cost Index, which

measures exploration and production costs of the oil and gas industry as a whole, more than doubled over the past decade. By comparison, during the same period, the cost of a new gas liquefaction plant grew far more rapidly, by a factor of four or five times.

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By Michael Stoppard @MStoppard

2015LOW OIL PRICES AND LNG

WITHSTANDING THE ROUGH SEAS AHEAD

IHS (NYSE: IHS) is the leading source of insight, analytics and expertise in critical areas that shape today’s business land-scape. Businesses and governments in more than 150 countries around the globe rely on the comprehensive content, expert independent analysis and flexible deliverymethods of IHS to make high-impact deci-sions and develop strategies with speed and confidence. IHS has been in business since 1959 and became a publicly traded company on the New York Stock Exchange in 2005. Headquartered in Englewood, Colorado, USA, IHS is committed to sus-tainable growth and employs about 8,800 people in 32 countries around the world. IHS is a registered trademark of IHS Inc. All other company and product names may be trademarks of their respective owners. © 2015 IHS Inc. All rights reserved.

This special section was prepared by IHS research staff and did not involve The Wall Street Journal news organization.

About IHSwww.ihs.com The rapid drop in oil prices and continuing geopo-

litical and economic uncertainty are buffeting both the energy industry and many countries and will continue to have a significant impact on the world economy in 2015. These developments raise critical questions: How will the oil-price collapse affect the energy industry and the global economy? What will be the price path from here? Is the United States the new “swing producer”? What will happen to energy demand, with the United States growing robustly and a mixed outlook in Eu-rope and China? How will geopolitical upheaval, with trouble breaking out in multiple global hot spots, affect energy supplies? How much of a threat are cyberat-tacks and what can be done to respond? Are there new transformative innovations on the horizon that could have an impact like hydraulic fracturing has had over the past decade? And what role will policy and regula-tion play, especially leading up to the Paris climate talks next December? This special section, Turning Point: Energy’s New World, addresses several key issues at the heart of the current energy picture: • How the drop in oil prices is creating turbulence for the

liquefied natural gas industry; • The “missing money problem” in the electric power

sector that will hinder new investment and lead to premature shutdowns of existing facilities;

• “Standardization” as a significant opportunity for the oil and gas industry to reduce costs of major projects;

• Why China’s energy demand is now growing more slowly and what it means for the rest of the world.

Yesterday’s special section examined future pros-pects for oil production in the United States, the rise of utility-scale solar generation and the implications of Europe’s new Energy Union. We are pleased to partner again in these special sections with The Wall Street Journal during the 34th IHS Energy CERAWeek conference, April 20-24, in Hous-ton, Texas. CERAWeek is recognized as the preeminent gathering for the global energy industry. This year’s con-ference will feature presentations and interactive ses-sions by more than 250 senior executives, government officials, thought leaders and IHS experts. We anticipate attendance of nearly 3,000 participants from more than 55 countries. Join us online at www.ceraweek.com As we embark on our 34th CERAWeek conference, we invite you to share in new perspectives on the energy future through the insights in these pages.

Daniel YerginIHS Vice Chairman and

Chairman of IHS CERAWeek

Author of The Quest and The Prize @DanielYergin

ILLUSTRATIONS BY ALEX WILLIAMSON

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THE ELECTRIC POWER INDUSTRY’S MISSING MONEY PROBLEM

Aquarter century ago, a large-scale restructuring of the electric power industry got underway in both North America and Europe. The effort was termed “deregulation” on this side of the Atlantic and “liberal-ization” on the other. But things do not always work out according to plan — and that is what happened here. Restructuring in the United

States never reached its intended end state because of what economists call “the missing money problem.” This is a market failure arising from the quite distinctive cost structures of the technologies involved in power generation that prevent electricity markets from working the way the marketplace does in economics textbooks. The problem can be summed up this way: Competitive forces drive rival suppliers (who have already built their power plants) to bid to provide electricity in the market at prices high enough to cover variable costs but too low to cover total costs. The resulting gap between market clearing pric-es and average total costs causes too many power plants to retire before it is economic for them to do so. Similarly, chronically low prices prevent the time-ly development of new power supply. The combination of too few new power plants being built and too many existing power plants closing down threatens the future adequacy of America’s power supply. How well — or poorly — power systems address the missing money problem today and in the years to come will be one of the key factors shaping the future of the electricity sector.

The missing money problem arises because of the inherent characteristics of electric power produc-tion. Building a power generation facility requires a large up-front expenditure, and these fixed costs can-not be altered in the short run. Consequently, for electricity generated by conventional technologies — which still account for more than two-thirds of world supply — fuel is the only significant input that can alter the amount of power generated in the short run.

A modern natural gas-fired power plant built in North America can produce electricity at an average total cost — which includes the up-front investment — of around 14 cents per kilowatt-hour (kWh) at low utili-zation rates and around 7 cents per kWh at maximum utilization. Variable costs account for a little over half of total costs. When owners of rival facilities with these cost characteristics bid against each other in wholesale markets, they are willing to provide additional electricity for any price above the variable cost because supplying power at that price provides some contribution towards fixed costs. Consequently, competitive forces tend to drive market-clearing prices to short run marginal costs. But here’s the catch: As power plant utilization rates in-crease, the gap between incremental costs and average total costs narrows, but does not fully close (see chart).

As a result, when power demand and supply are in balance — including reserve capacity needed to insure reliability — the market-clearing price remains below av-erage total cost. The average power plant utilization rate in the U.S. is around 45 percent. At this rate, the marginal cost-based price only covers about half of the average total cost. As the example above shows, suppliers that sell their power in wholesale markets face a significant missing money problem.

The missing money problem surfaces in even starker relief with generation technologies such as hydro, wind and solar. These require no fuel, so the short-run mar-ginal cost of production is effectively zero. Suppliers of electricity from these sources therefore face short-run incentives to offer their power at any price greater than zero. As a result, when hydro, wind and solar are com-peting to meet a change in demand, the market-clear-ing price tends to be driven toward zero. This problem is most pronounced in the liberalized power markets of Europe.

In the United States, the missing money problem is made worse by policies that subsidize renewable power, which exist in 38 states. When renewable power sources compete in wholesale markets, their owners recognize that losing a bid means losing the opportunity to collect subsidies. Consequently, owners of renewable power sometimes respond by bidding negative prices — effec-tively offering to pay customers to take their power — as long as the available subsidies can more than cover sums paid to customers.

Besides depressing energy prices, renewables such as wind and solar also typically increase the costs of con-ventional generation. This is because power systems need conventional generating technologies to back up and fill in for intermittent renewable sources. But doing so makes utilization rates at conventional plants lower and more varied. These so-called added “integration” costs only worsen the missing money problem.

Market-based pricing and well-intentioned subsidies for renewable power have therefore brought about an unexpected result. Prices on wholesale electric power markets chronically settle at levels below those required for producers to recover the full cost of their operations. This has had a very notable effect on merchant power suppliers. These are companies that specialize in pro-ducing electricity and selling it to wholesale markets, but do not own the wires that distribute electricity to home-owners and businesses in particular cities or regions. The missing money problem was one of the primary reasons why bankruptcy reorganization was the rule rather than the exception for merchant generators in the era of de-regulation. Over the last 15 years, these merchant gen-erators have written down billions of dollars of power plant investments.

The missing money problem has three major conse-quences. The first is the risk of underinvestment in new power supply. Second, low prices are causing many existing power plants to be retired early, even though their continued operation would be far less costly than replacing the supply they now provide. Several nuclear plants have closed prematurely in the past few years and more than a dozen are vulnerable to closure in the years

2015

By Lawrence Makovich

Continued on next page

AVERAGE AND INCREMENTAL COST OF TYPICAL U.S. NATURAL GAS-FIRED COMBINED CYCLE

POWER GENERATION PLANT

$0.00

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2015

World oil prices have fallen by half since last autumn. Even before the collapse, reduc-ing costs was already seen as a priority. Now it is an absolute necessity. And it’s

high time. Prior to the recent crash, oil prices had hovered around $100 per barrel for almost half a decade. Despite high prices, oil and oil services companies have posted modest recent returns, due to their burgeoning costs.

Why the increased costs? A major reason is the complexity of many exploration and develop-ment projects. This complexity rose as companies tapped into deeper water, tighter rock and mature fields that required more operational attention. Moreover, many new projects were in emerging markets or remote areas with limited infrastructure, and operat-ing in such locations also drove up costs. In addition, rising global demand for skilled workers and for com-modities such as steel led to higher supply chain costs. IHS tracks major aspects of upstream costs, and its capi-tal costs index and other relevant indices have more than doubled over the past decade (see chart).

It’s now imperative that oil and oil services companies reduce costs to maintain viable returns. The industry has faced downcycles before and knows the usual responses well: convince suppliers to provide the same for less; ra-tion capital spending; restructure internally to reduce overhead; and try to negotiate better terms with host governments. An additional avenue for reducing costs today is adoption of innovative technologies such as automation/unmanned systems, advanced sensors and sophisticated data analytics.

Oil and oil services companies are already busy try-ing the approaches listed above. But there is another re-sponse as well that could enable a step-change advance in cost performance. This would be to get back to basics and simplify the problem. How? Through greater reli-ance on industry-wide standards.

First, it’s important to understand what standards are: best practices agreed upon by industry participants. For example, the American Petroleum Institute (API) has created committees of experts from a wide array of oil and gas operating companies, equipment suppliers and services companies to agree on best practices (or stan-dards) for designing, installing and maintaining pumps and valves to maximize safety, reliability and operational efficiency. Adhering to standards can be mandatory and enforced by regulation, as with the American Society of Mechanical Engineers’ (ASME) Boiler & Pressure Vessel Code. Many other standards are voluntary.

Standards can also ensure efficient interoperability across different manufacturers, enabling a competitive market and facilitating faster adoption of new technol-ogy. Because of standards, any gas station you pull into has a pump that will fit your car. Your laptop connects to your mobile phone, as well as your printer and your wireless router, even though they are from different manufacturers. This is because companies in the tech industry adhere to common standards for how these devices connect.

Companies active in oil and gas exploration and pro-duction (E&P) today rely heavily on industry standards. It is estimated that the 120,000 engineers working for the top 500 energy companies in the world relied on 80,000 different industry standards from over 135 stan-dards bodies. But most oil and gas companies also complement industry standards with their own internal proprietary standards to build, maintain and operate their upstream infrastructure. These internal standards may leverage industry-approved standards as a start-ing point, but companies then often layer on additional company-specific requirements to ensure reliability and safety, increase efficiency, address challenges seen on past projects, improve maintainability, encapsulate cor-porate practices, and reflect the perspectives and experi-ence of internal groups. As an illustrative example, an oil and gas company could decide that all of their electrical equipment boxes be painted orange instead of industry-standard green.

Oil companies are now realizing that proprietary stan-dards can significantly drive up costs, while industry-wide agreement on common standards can spread costs across a larger base and thus reduce them. Companies that rely on internal standards typically spend between 20 and 100 percent more than those that rely on industry standards. And in some cases, the costs associated with proprietary standards can be as much as 10 times greater. Why? In the case of the orange electrical equipment box cited above, the color change leads to extra manufactur-ing time and also requires the supplier to carry addition-al inventory. In the case of large, complex E&P projects, engineers at the engineering, procurement and con-struction (EPC) firms that build upstream infrastructure have to get up to speed on different proprietary require-ments for every project, which limits knowledge reuse and scale, thereby adding costs and delaying schedules. Across thousands of projects in the industry, the impact is billions of dollars in additional costs and delays.

Internal standards are also difficult to maintain. In most cases, the rationale behind internal standards re-sides in the minds of senior engineers who have worked at their companies for decades. But the oil industry now faces what observers call the “Big Crew Change.” Oil companies hired many Baby Boomers during the 1970s and early 1980s, when prices were high during and after the oil crises of the 1970s. But between the mid-1980s and the start of the new century, hiring was modest. As

a result, many technical professionals in the indus-try are nearing retirement age, and there is a dearth of mid-career people ready to replace them. As Baby Boomers retire — and over the next five to 10 years, it is estimated that 50 percent of U.S. petroleum en-gineers will be eligible to do so — the expertise re-quired to maintain customized internal standards is being lost. The challenge becomes even greater as oil companies postpone hiring or reduce headcount to cut costs in the wake of the price drop.

IHS has been researching this question and has found that oil companies can replace a significant percentage of internal proprietary standards with industry standards while maintaining the same lev-els of reliability and safety. And shifting away from proprietary standards can provide dramatic cost im-provements of more than 25 percent and faster time to market.

How can companies take advantage of standards to cut costs? By adopting industry standards and making them more robust.

A first step is to move away — where feasible and ap-propriate — from proprietary standards, or from custom adaptations on top of industry standards, and toward adoption of pure industry standards.

There are also opportunities to make the standards that exist more useful and effective. Many industry standards settle on only basic requirements because it’s easier to get companies to agree on them. Also, in some instances, multiple standards-setting bodies lead to overlapping or conflicting rules; when this happens, there isn’t a clearly accepted standard that the entire in-dustry agrees to uphold. Because of practices like these, there are now, for example, over 328 industry standards that apply to valves. But the executive-level mandate to cut costs has given the industry a compelling reason to drive the difficult-to-achieve consensus needed to de-velop better and more complete standards. New indus-try working groups can be created to forge consensus, with senior executives from leading companies provid-ing the impetus for change.

This is no theoretical prospect. The aerospace sector has shown that widespread adoption of industry stan-dards can drive unprecedented cost benefits, along with safety enhancements, while still allowing firms to achieve competitive advantage on the basis of their distinctive capabilities. In addition, the United States Department of Defense (DoD) MilSpec Reform effort in the 1990s demonstrated that with the right level of leadership attention, dramatic reductions in proprietary standards and broad adoption of industry standards can be achieved. In the case of the DoD effort, billions of dol-lars have been saved.

This year, capital spending by the energy sector for exploration and production is expected to total nearly $750 billion. Reducing those expenditures by even a few percentage points could lead to savings totaling tens of billions of dollars. The potential is therefore huge. Today’s low energy prices provide strong incentives — and indeed the urgent need — for oil and oil services companies to embark on the path toward a new level of industry standards.

Paul Markwell is Vice President of Upstream Oil & Gas Consulting at IHS. Chad Hawkinson is Senior Vice President of Standards and Engineering Excellence at IHS.

THE URGENT NEED TO REDUCE OIL INDUSTRY COSTS

to come. Left unaddressed, the missing money problem could lead to a reprise in other regions of the power shortages that plagued California in 2000-2001, when consumers experienced dramatic price spikes, brownouts and rolling blackouts. Third, low prices distort market signals and lead to an inefficient mix of fuels and technologies. IHS estimates such inefficiencies are moving the cost of fuel used to generate electricity in the United States to a level 9 percent higher than it should be.

There is no one-size-fits-all solution

to the missing money problem. Each regional power system has its own char-acteristics, and the best mix of solutions in any particular setting will depend on the distinctive characteristics of that sys-tem. But IHS, in consultation with key industry stakeholders, has identified 13 different approaches currently being employed, or considered, to address the missing money problem. On the table are a whole range of approaches from adding capacity markets to moving back toward more regulation or public owner-ship. There is much debate about what to do. No one-size-fits-all solution exists

because current regulatory and mar-ket conditions vary significantly from one regional power system to the next. Evaluating these approaches against multiple criteria has shown that some approaches, alone or in combination, can meaningfully address the missing money problem. Conversely, some ap-proaches are not likely to provide the building blocks of an effective solution under any conditions — and could make matters worse.

Any measures put forward to address the missing money problem should re-flect the interests of all key power sector

stakeholders: electricity generators and operators of wholesale markets, as well as consumers, elected representatives and regulators. Implementing effective solutions will first require convincing power-system stakeholders that a prob-lem exists as well as getting them to agree on its nature and causes. Only then will they be able to reach consensus on an ef-fective suite of remedies. And it is better to do all this before a crisis than after.

Lawrence Makovich is Vice President and Senior Advisor for Global Power at IHS and lead author of the IHS Multiclient Special Report, Bridging the Missing Money Problem.

IS STANDARDIZATION THE KEY?By Paul Markwell and Chad Hawkinson

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IHS Energy Analysis Related to Today’s ArticlesGLOBAL LNG SUITE Provides ongoing research and analysis of the

complete LNG value chain, including short-term trade

forecasts and long-term trends.

BRIDGING THE MISSING MONEY GAP This study identifies the causes of cash-flow short-

falls in the electric power industry and recommends

cost-effective solutions.

INDUSTRY STANDARDIZATION SERVICE IHS provides information, software and expertise

to help companies optimize internal standards and

transition more effectively to industry standards.

CHINA ENERGY SERVICES Provides comprehensive insights into the world’s

largest and fastest-growing energy market, including

oil and gas, power, coal and renewables.

To learn more, contact Peter.Augustini@ihs.com

UPSTREAM CAPITAL COST INDEX

SOURCE: IHS

Continued from previous page

ILLUSTRATION BY ALEX WILLIAMSON

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WHAT IS HAPPENING TO CHINA’S DEMAND FOR ENERGY?

After a decade of phenomenal expan-sion, the growth in energy consump-tion in China appears to be slowing

down. Whether oil or natural gas, elec-tricity or coal, the rate of growth has been decelerating compared with the pace just a few years ago (see figure). “Go to China” was long the mantra for energy compa-nies around the world. But many players are asking a very different question today: What happened to what was thought to be China’s insatiable appetite for energy? The firms that targeted China are feeling much justified anxiety. They will all need to ad-just to the new reality of slower growth.

What is behind this slowdown in the growth of energy consumption in China? It is the rebalancing that is now going on in China’s overall economy. The previ-ous investment-led model of growth is giving way to greater reliance on domes-tic consumption. That is already evident in the numbers. Investment is no lon-ger the main engine of China’s growth: Consumption accounted for 49 percent of GDP growth in 2014, compared with 41 percent through fixed-capital formation. The shift to relying more on domestic consumption has also led to less em-phasis on exports. With two of the three long-standing GDP drivers — investment and exports — slowing, overall economic growth was down to 7.4 percent in 2014.

Beijing appears content with this change in direction. The prime minister has even modified the official growth rhet-oric in public speeches from the decade-long motto of “relatively high growth” to “medium-high growth.” IHS Economics expects China’s growth to slow further to 6.5 percent in 2015 and 2016.

Energy consumption has already re-sponded. Between 2001 and 2011, China’s oil demand doubled to reach more than 9 million barrels per day (mbd). The country accounted for over half of the incremen-tal increase in global oil demand during that period. Since 2011, however, growth has weakened greatly, expanding at only 4 percent annually instead of the average rate of 8 percent during the prior decade. Industrial fuels (diesel, fuel oil, naphtha)

were chiefly responsible for this slow-down, due to the deceleration in industrial growth. And IHS Energy expects Chinese oil demand to grow at only 3 to 4 percent annually over the next few years.

Electric power demand in China grew 12 percent per year on average between 2002 and 2011. The country’s power generation fleet tripled in size, making it the largest in the world. In the mid-2000s, China was add-ing as much capacity each year as now ex-ists in all of France or Great Britain. Power consump-tion growth since 2011, however, has averaged only 6

percent per year. The investment-to-con-sumption shift hits power demand espe-cially hard, since industry accounts for 70 percent of China’s electricity consumption. Relatively slow growth in power demand is expected to continue, in line with the eco-nomic outlook.

Meanwhile, substantial new capac-ity additions are still coming online. New hydro projects slated to enter service over the next three years, for example, would be sufficient to supply the electricity needs of the entire country of Austria. The decisions to invest in these large projects were made when China’s power consumption was still growing at double-digit rates. But approval and construction took time. These proj-ects’ entrance into service is now expected

to lead to lower average utilization hours for power plants. This will have significant implications for power producers, equip-ment manufacturers and fuel suppliers.

The coal sector is acutely feeling this slowdown as nearly three-quarters of China’s electricity is generated from coal. In 2014, for the first time this century, Chinese coal consumption and raw coal production both declined. And with a con-certed policy drive underway to curb air pollution in coastal cities, it is likely that coastal China’s coal demand has peaked

and is now in long-term decline. This was unthinkable only a few years ago. Coal prices have fallen precipitously from a high of over RMB 840 ($130) per ton in 2011 to less than RMB 500 ($80) today.

Coal’s main competitor in many mar-kets — natural gas — is also affected. As recently as 2010, China was in desperate need of more gas, with demand outpac-ing domestic supply. In response, China’s national oil companies signed many long-term contracts for liquefied natural gas (LNG). Today, these commitments are starting to deliver and will all materialize in the next three years. But there are now questions about whether China can use all this new supply. Last summer, for exam-ple, spot LNG imports into China dried up,

and spot prices last winter, usually a peak demand season, were reported to be less than $7 per million BTU, from as high as $20 several years ago.

A decade of robust demand growth and high commodity prices made many for-get the cycles that are endemic in the en-ergy industry. The recent supercycle made China one of the most important drivers in the global energy system. Because of that, its deceleration is of particular importance for the world. The outlook in China now is for slower growth in oil demand, decreased

coal-fired power plant utilization, overcapacity in coal mines and slower uptake for imported gas.

While these trends pose risks for compa-nies that have invested in China, they also cre-ate potential opportu-nities. Investment in long-distance power transmission lines could unlock cheap coal and other resources in Western China; this means that even though coastal coal consump-tion has peaked, nation-al demand for coal will continue to grow well into the 2020s. The more

abundant supply of global gas — combined with Beijing’s push for cleaner fuels and gas infrastructure reforms — also means that Chinese utilities may be able to procure gas directly in the international market to meet continued demand growth.

It must be remembered that after a de-cade plus of rapid growth, China’s base of energy demand is many times bigger than at the start of the century. So even a slower rate of growth on this much larger base nonetheless produces large increases in incremental demand. This means new supply will still very much be needed.

Xizhou Zhou is Senior Director and Head of China Energy at IHS; he leads the firm’s flagship China Oil & Gas Service and China Gas, Power & Coal Service.

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By Xizhou Zhou

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Coal demand

Electricity demand

Diesel demand