Upstream Oil & Gas - Low Oil Prices Are Challenging Natural-Gas Markets

Low Oil Prices Are Challenging Natural-Gas Markets

After three years of relative stability, oil prices have fallen sharply since mid-2014. The effects of this drop on a wide range of energy companies have been material, with many players forced to rethink investments, cost structures, and even business models. And a high degree of uncertainty about where oil prices will go next remains. Will prices bounce back, as history suggests they will? Or have we entered a “new normal” consisting of a fundamentally different pricing environment?

Global natural-gas markets have already felt some impact from the slide in oil prices. But those markets will be affected to a much greater degree if oil prices remain in the $50-to-$60-per-barrel range for an extended period, given the interaction that exists between the two fuels. Gas prices in some markets are still contractually tied to oil prices; there are also substitution effects—users switching between oil and gas in response to changes in pricing dynamics.

Gas markets will not react uniformly, however, because of a host of market-specific factors. Below we examine the three core markets—the U.S., Asia, and Europe—to gauge their likely response to a protracted period of low oil prices and to identify where some of the resulting risks and opportunities for industry players might lie.

The US Market: Falling Demand and Supply

Sustained low oil prices will put downward pressure on both demand and supply in the U.S. natural-gas market. Let’s look first at demand.


In 2014, U.S. natural-gas demand totaled 690 billion cubic meters (bcm), with the residential and industrial segment accounting for two-thirds of that total, and power generation the rest. The U.S. remains a net importer of natural gas, with net imports of approximately 35 bcm in 2014, primarily from Canada. But imports have fallen sharply since the last decade, when the U.S. was importing roughly 100 bcm per year.

The U.S. Energy Information Administration (EIA) projected that U.S. demand for natural gas would total 770 bcm in 2020. This projection, however, was issued in early 2014 (that is, before the decline in oil prices) and assumed demand growth across all major segments: natural-gas exports (driven by growth in exports of LNG, or liquefied natural gas, associated with the development of LNG projects); transportation (led by particularly strong demand growth from trucks, with compressed natural gas increasingly substituting for diesel fuel and gasoline); power generation (with gas increasingly replacing coal-fired generation); and the residential and industrial segment (owing mainly to an uptick in industrial activity). Given that oil prices have been halved since mid-2014, however, some of those assumptions—specifically for exports and transportation—must be revisited.

Let’s look first at exports. The EIA projected that U.S. LNG exports would exceed 70 bcm in 2020, propelled by the price competitiveness of U.S. supplies in the global arena. But the fall in oil prices undermines that assumption. For U.S. LNG exports to appeal to buyers in Asia and Europe, spreads between U.S. Henry Hub prices and prices in Asia (which are indexed to the price of oil) and Europe (which are indexed mainly to prices at hubs such as the U.K.’s National Balancing Point and the Netherlands’ Title Transfer Facility) must be sufficiently wide. But spreads have narrowed considerably as oil prices have fallen.

This is illustrated by the narrowing of the spread between the free on board (FOB) cost of U.S. LNG exports from the East Coast and Asian LNG import prices as oil prices have fallen.1 Notes: 1 The FOB cost of LNG exports from the U.S. East Coast stands at approximately 115 percent of Henry Hub prices plus $3 per MMBtu of liquefaction. Asian LNG import prices stand at about 14 percent of JCC DES (Japan Customs cleared, delivered ex ship). Under FOB agreements, a seller is required to deliver goods by means of a vessel designated by the buyer. The seller fulfills its obligation when the goods have passed over the ship’s rail. JCC is the average price of customs-cleared crude-oil imports into Japan. Under DES agreements, the seller is required to deliver goods to the buyer at an agreed-upon port of arrival. The seller remains responsible for the goods until they are delivered. When oil was $100 per barrel, the spread was between $6.40 and $7.60 per million British thermal units (MMBtu). (To calculate this range, we have assumed a Henry Hub price of $3 to $4 per MMBtu.) If oil prices remain in the $50-to-$60 range for an extended period, the spread will collapse to between –$0.60 and $1.95.

Given the narrowed spread and current LNG transportation costs from the U.S. East Coast to Asia (approximately $2.50 to $3.50 per MMBtu), the economics of the U.S. exporting LNG to Asia look increasingly less compelling. Exhibit 1 shows how the competitive position of U.S. LNG exports in Asia could evolve if the recent pricing environment—oil in the $50-to-$60-per-barrel range, and Henry Hub gas at $3 to $4 per MMBtu—were to prevail for an extended period.

As a consequence of these dynamics, we expect to see delays in, and ultimately cancellation of, some LNG-export projects in the U.S. Mature projects that have already passed major regulatory milestones, and whose companies have secured firm long-term commitments for the project’s capacity from reputed buyers, will probably move forward and be completed on schedule. Such projects would include Cheniere Energy’s Sabine Pass terminal (on the border between Texas and Louisiana), the Freeport terminal (Texas), and the Cameron terminal (Louisiana). Prospects for other projects are more uncertain. Some projects that are at earlier stages of development but for which long-term customer commitments have been secured might advance, albeit with the potential for significant delays. This category includes Sabine Pass T5-T6, the Freeport expansion, Cheniere Energy’s Corpus Christi terminal (Texas), Dominion Resources’ Cove Point terminal (Maryland), Southern Union and BG Group’s Lake Charles terminal (Louisiana), and the Golden Pass terminal (Texas). Delays are especially likely for projects whose main customer is a portfolio buyer seeking to resell the product to third parties. Projects for which long-term buyer commitments have not been secured will likely be shelved until spreads widen.

In light of the above analysis, we expect U.S. natural-gas exports in 2020 to be in the range of 40 to 50 bcm—well below 70 bcm.

Projections for demand growth from the transportation segment must be similarly ratcheted down. The EIA estimated that demand would grow by 8 percent per year until 2020 and reach approximately 2 bcm that year, with high price differentials between natural gas and oil products, most critically diesel fuel, leading to increased substitution of the former for the latter. (This scenario obviously assumes sufficient development of the enabling downstream infrastructure.) But with oil at $50 to $60 per barrel, that outcome seems far less likely. In fact, barring a recovery of spreads between diesel fuel prices and Henry Hub prices, we expect demand from the transportation segment to be less than 1 bcm in 2020.

The decline in oil prices will have far less impact on demand for natural gas from the power-generation and residential and industrial segments. U.S. demand for natural gas from power generation is spurred largely by competition with coal (and, to a lesser extent, renewable generation). Indeed, about 70 percent of the country’s power is produced using natural gas and coal; less than 1 percent, using oil products. Hence low oil prices should have little influence on the demand from power generation.

Demand from the residential and industrial segment should also be relatively unaffected by lower oil prices. Retail gas prices in the U.S. are set by Henry Hub prices, whose dynamics are decoupled from those of the oil market. Natural-gas prices are also competitive with oil prices at their current levels, reducing any incentive among users to substitute natural gas for oil products such as liquefied petroleum gas (LPG) and even fuel for heating.

All told, assuming oil prices remain in the $50-to-$60 range, U.S. demand for natural gas will certainly fall short of longer-term projections made before the downturn in prices. We expect demand in 2020 to be roughly 740 bcm—well below the EIA’s 2014 forecast of 770 bcm.


The fall in oil prices will also lead to a lower supply of natural gas in the U.S. market, since oil and gas companies are likely to scale back development. There are a number of reasons for this. One is that these companies’ current portfolios of upstream investments were established when oil was priced at $100 per barrel. With oil prices at current levels, the costs of many of these projects are now high compared with their expected revenues, and it will take the industry some time to adapt its cost structures to the new pricing environment. Until that happens, investment activity will be curtailed.

This situation will be exacerbated by the fact that, with cash flows from their currently operating oil fields shrinking, oil and gas companies have less cash to invest. This will force them to be increasingly selective in the investments they do make, and projects with relatively high break-even prices, which would include some gas-development projects in the current environment, could be delayed or canceled.

Further, a relevant share of natural-gas production in the U.S. comes from wet reservoirs. The relatively high value of the natural-gas liquids (NGLs) that these reservoirs produce has been a core source of profitability for the energy industry over the past several years, when oil prices were in the $90-to-$110 range. With oil priced at current levels, however, the break-even price of wet shale-gas development projects has risen, reducing companies’ incentive to drill.2 Notes: 2 If oil prices were to remain low for an extended period, though, it’s possible that a reduction in natural-gas supply could push Henry Hub prices higher, which could offset the impact of falling NGL prices on energy companies’ finances. Henry Hub prices could rise by as much as $1 per MMBtu, depending on the industry’s ability to reduce the cost of new developments.

Considering the demand and supply dynamics in aggregate, it seems clear that a prolonged period of low oil prices would lead to a smaller U.S. natural-gas market. It would also limit the U.S.’s role as an exporter of LNG, retard the development of natural gas’s role in the transportation sector, and reduce the price competitiveness of U.S.-produced natural gas on the global market. There are two factors, however, that could influence the prices of U.S. LNG exports and ultimately keep U.S. exports competitive, even in the face of an extended period of low oil prices. The first is the ongoing advancement of shale development technologies in the U.S. The second is the opening of the new Panama Canal, which will reduce transportation costs from the U.S. East Coast to the Far East.

The Asian Market: Lower Prices and Less Urgency for Index Diversification

By region, Asia has had the world’s fastest growth in demand for natural gas in recent years, with demand rising by more than 6 percent annually for the past five years, surpassing 600 bcm in 2014. Historically, Asia has relied heavily on imports to satisfy its demand, given relatively limited local production. To ensure security of supply, Asian buyers have relied principally on long-term contracts, largely indexed to oil prices. The link to oil prices also reflects the region’s growing substitution of natural gas for oil products when this strategy was initiated.

Given the linkage of Asian gas contracts to oil prices, the recent fall in oil prices will directly impact Asian gas prices, pushing them significantly lower. This will be increasingly evident in the months ahead, as existing long-term gas-import contracts are indexed to oil with a time lag that ranges between 6 and 12 months. The impact to date can be seen in Exhibit 2, which compares the recent evolution of two natural-gas price references in Asia: the average LNG import price in Japan and northeast Asian LNG spot prices.

As the exhibit shows, northeast Asian LNG spot prices have already fallen significantly. Natural gas delivered under long-term supply contracts, as represented by the average LNG import price in Japan, will show increasingly steep declines after the first quarter of 2015. We expect that if oil prices remain at current levels, Asian LNG import prices will fall to about $7 per MMBtu by mid-2015, reflecting the fact that long-term contracts’ oil indexation is typically based on oil’s average price over the past 6 to 12 months. In fact, current futures pricing is already discounting this likely price decrease.

Another factor that will weigh on the Asian LNG market is planned LNG development projects in Australia and Papua New Guinea, which could introduce roughly 90 bcm per year to the market. This added volume will increase downward pressure on prices; it will also reduce Asian buyers’ incentive to integrate upstream. We expect, however, that there will be delays of approximately two years in the launch of many of these projects, which will give the market time to balance supply and demand in advance of this added pressure on prices.

A key near-term effect of lower oil prices—and one that could remain in place over the longer term if oil prices stay low—is a reduction in the perceived need among Asian LNG buyers for index diversification. Over the past few years, Asian buyers have looked to broaden the basket of indices they use when securing LNG supply, with a particular push to move away from oil in favor of Henry Hub–indexed volumes, whose prices became increasingly attractive compared with prices for oil-indexed volumes when oil was about $100 per barrel. With oil prices now well below that, and with more uncertainty over the competitiveness of U.S. LNG, Asian buyers have to review their diversification strategies.

Over the medium to longer term, it seems likely that if the current oil-price environment persists, it will enhance the sustainable development of the natural-gas market in Asia.

The European Market: Downward Pressure on Prices

The European natural-gas market has evolved into a market with significant liquidity. In 2013, for example, the volume of gas traded in all of the region’s hubs combined exceeded natural-gas demand in those countries by a factor of ten.

Today, most volumes in Europe are indexed to hub prices, which are decoupled from oil prices. This decoupling was quite evident in 2014, when oil prices and European natural-gas prices moved in largely opposite directions for much of the year. (See Exhibit 3.)

The relationship between oil prices and natural-gas prices has changed significantly in Europe in the past decade, reflecting an evolution of the indexation structure of gas contracts in the region. In 2005, about 70 percent of European natural-gas volumes were indexed to prices of oil and oil products; by 2013, almost 80 percent of volumes were indexed to hub prices, with only about 20 percent still indexed to prices of oil and oil products.

This change in European market structure is a direct consequence of several rounds of renegotiations between European midstream players (including E.ON, RWE, GDF Suez, and Eni) and their main natural-gas suppliers (such as Gazprom, Statoil, GasTerra, and Sonatrach). This effort was undertaken several years ago by midstream players with the goal of adapting their supply portfolios to the prevailing gas-market environment. The effort remains in progress, so we expect hub-based indexation in Europe to continue to increase.

For European natural-gas contracts that remain indexed to oil prices, the decline in the price of oil has had a direct impact on contract prices. Hence holders of these contracts have less pressure to renegotiate them. However, we think that over the longer term, oil indexation will remain a risky strategy for midstream players, given the enormous potential for margin volatility.

The risk of an oil indexation strategy to relevant European midstream companies could prove even greater in the near to medium term, given the indirect effect of falling oil prices on the European market. Europe acts as a sink for surplus international LNG volumes. In a scenario of low LNG prices in Asia, some LNG-supplying countries, such as Qatar, and LNG portfolio players could redirect part of their volumes to the European market, thus fostering competition in Europe between traditional pipeline suppliers (namely, Norway, Russia, and Algeria) and core LNG sellers. This could push gas prices in European hubs to levels below the prices of natural-gas contracts that are indexed to oil and oil products at current prices.

The sharp decrease in oil prices has material implications for all three major natural-gas markets. In the Asian market, the impact will be direct: there will be less pressure on Asian buyers to renegotiate contracts and less perceived need for index diversification and upstream integration.

In the U.S. and European markets, the impact will be indirect. If oil prices remain in the $50-to-$60 range, the likeliest outcomes in the U.S. market are delays in LNG projects and lower growth in demand for natural gas due to uncertainty over the competitiveness of U.S.-produced LNG. U.S. gas prices could also possibly increase, given higher development costs driven by the low value of NGLs. In the European market, we expect lower gas prices and potentially increased volatility in hub prices, owing to Europe’s role as a sink for LNG volumes in the current market context.

Low Oil Prices Are Challenging Natural-Gas Markets