In 2009, unconventional shale gas emerged as the dominant driver in North American natural gas markets. Rapid increases in shale gas production and shale-driven upward revisions to the U.S. natural gas resource base have reversed the outlook for the U.S. natural gas supply. In contrast, the economic recession and growing uncertainties around the role of natural gas in power generation have clouded the outlook for natural gas demand. Natural gas has been called the “bridge fuel” for its potential to support the transition to a low carbon U.S. economy. But without a growing market, natural gas could be on a bridge to nowhere.
After peaking in July 2008 at around $13/MMBtu, U.S. natural gas prices fell dramatically in 2009, reflecting oversupply conditions caused by surging shale gas production and the sharp impact of the recession on industrial gas demand. At their lowest, cash prices at Henry Hub fell below $2/MMBtu in September 2009 and the low natural gas prices over the summer caused significant displacement of coal-fired power generation. U.S. natural gas prices rebounded in the second half of 2009 and ended the year in the $5 - $6/MMBtu range.
The power generation sector will be the primary driver for future U.S. natural gas demand. The power generation sector comprises over 50 percent of the total gas demand increase from 2010-2034 in our forecast. It isn’t a stretch to say the natural gas market is dependent on the power generation sector.
The residential, commercial, and industrial sectors for natural gas are mature or declining. These sectors face a combination of increasing efficiency of natural gas use and static consumption. Two exceptions prove the rule. First, ethanol refineries were only a significant factor for growing natural gas demand in a handful of corn-producing states. Second, while much has been said about using natural gas in the transportation sector, today the amount of natural gas used in that sector is barely noticeable and almost exclusively limited to fleet vehicles. Support appears overwhelming for all-electric and electric hybrid vehicle technology and not for direct use of natural gas as a transportation fuel for passenger vehicles.
Given this dependence on the power generation sector, the outlook for natural gas hinges on a small set of key power industry issues, including the timing of economic recovery and load growth; federal carbon policy and support for renewables; and investments in baseload power generation. There are uncertainties around each of these issues and the overall impact clouds the picture for natural gas market growth.
Natural gas prices fell dramatically in 2009, reflecting oversupply conditions. Annual average Henry Hub prices were below $4/MMBtu in 2009— a level not seen since 2002 (see Figure 1). Average annual prices on the NYMEX natural gas forward curve out three to five years averaged near $7/MMBtu in 2009, which is fairly consistent with expectations in 2006 and 2007 and serve to highlight the degree to which the market expected the natural gas oversupply situation to be short-lived.
On a regional basis, one of the most dramatic changes in 2009 was the increase in Rockies’ natural gas prices relative to Henry Hub. Rockies’ natural gas prices have increased, reflecting the increased pipeline capacity out of the region with the start up of the 1.8 Bcfd Rockies Express Pipeline (REX) being built by a partnership of Kinder Morgan, Sempra and ConocoPhillips. The REX pipeline out of the Rockies is part of a surge in U.S. gas pipeline infrastructure that includes the shale-driven pipeline infrastructure out of North Texas and the Midcontinent and LNG pipeline expansions. Approximately $10 billion was spent constructing natural gas pipelines in 2008, which was about five times the average for the previous 10 years, and 2009 and 2010 will be well above average as well. The supply sources behind the REX pipeline are primarily coal bed methane and tight gas; two unconventional gas resources that are prevalent in the Rockies and highlight that the improved outlook for unconventional gas production includes more than just shale.
Underground storage inventories reflected the oversupply conditions during 2009 with storage inventories well above the typical range based on the levels observed over the previous five years. Colder than normal weather in much of the U.S. this winter resulted in a strong drawdown in storage inventories. For example, in January 2010, storage levels dipped below the previous five-year maximum for the first time since May 2009, indicating that the supply glut of 2009 is no longer a primary driver for natural gas prices (see Figure 2).
The most dramatic change in storage levels occurred in the Gulf Coast production region, which has declined by over 600 Bcf since the start of December or an approximate 50-percent decline in 12 weeks. In fact, production region storage levels now are more than 100 Bcf below levels one year ago, after last summer’s surging shale gas production. Eastern and Western regional storage inventories have been drawn down to levels at, or just slightly above, levels from one year ago.
The over-supply condition in U.S. natural gas markets was exacerbated in 2009 by falling natural gas demand. U.S. natural gas consumption was down approximately 2.5 percent, largely due to sharply lower industrial sector consumption, which is down approximately 10 percent compared to 2008. In contrast, power generation sector natural gas demand was up approximately 3-5 percent despite relatively mild temperatures this past summer and relatively low electricity demand due to the impact of the economic recession. The increase in the use of natural gas for power generation came at the expense of coal-fired power generation, further highlighting the degree to which natural gas prices fell in 2009.
In the face of weak demand and collapsing prices, natural gas producers slashed capital budgets during 2009 and lowered exploration and development activity. An examination of the monthly break out of gas-directed drilling rigs illustrates the precipitous decline since the gas-directed rig count peaked at over 1,500 in September 2008 (see Figure 3). The shift toward unconventional production also is apparent as horizontal rig counts are down significantly less than other rig types and have begun to increase over the last several months suggesting that producers will continue to pursue shale development despite the fairly low price environment.
After months of holding steady despite falling prices and much lower rig counts, U.S. lower 48 natural gas production has shown some initial signs of decline. With fewer new wells being added, gas production could drop significantly in 2010, partly because of the shift to shale gas production and shale well’s typical high initial production decline rates.1 In addition, many areas of relatively expensive conventional production—such as the offshore Gulf of Mexico—are continuing to decline.
Liquefied natural gas (LNG) imports increased slightly during the summer averaging approximately 1.5 Bcfd compared to 1 Bcfd for most of 2008. This winter, U.S. LNG imports increased, reflecting additional deliveries into the Northeast U.S. in part due to: new liquefaction trains coming on-line; low global natural gas demand; and new import terminals coming on-line in Eastern Canada and the Northeast U.S. (see Figure 4). Most Gulf Coast LNG cargoes arrive under short-term or spot contracts. In general, Gulf Coast LNG imports have been the highest during the spring and fall when seasonal gas demand is lowest in other parts of the world. East Coast LNG cargoes include a portion of the deliveries under long-term contracts and in general, the terminals in the Northeast are expected to have higher utilization rates than those in the Gulf Coast.2 While LNG imports are starting to ramp up, Canadian gas delivered via pipeline continues to be the largest source of U.S. natural gas imports. While Canada was a growing source of natural gas supply to the U.S. market for many years, U.S. net pipeline imports were down approximately 1 Bcfd in 2009 compared to 2008, reflecting growing U.S. shale gas production, declining Canadian natural gas production, and increasing Canadian natural gas demand.
Natural gas demand growth from the power generation sector likely will accelerate over the long-term driven by carbon restrictions and other environmental pressures that eventually will encourage the construction of new natural gas-fired power plant capacity. Over the next 10 years; however, natural gas demand growth is expected to be anemic.
The predicted slow growth over the next ten years should occur at least in part due to the significant growth in natural gas-fired power generation capacity that occurred in the early part of the 2000s, which created an over-build of capacity in some U.S. power markets. Natural gas-fired power generation capacity essentially doubled from 1998 to 2004, from approximately 200 GW to approximately 400 GW (see Figure 5). Since 2004, natural gas-fired power generation capacity has continued to expand but at a much lower rate.
Since 1995, coal-fired power generation capacity essentially has been flat—as has nuclear and hydro-electric generation capacity. Oil-fired capacity has declined by approximately 10 GW. Renewable capacity began to grow in the last decade from a very small base, and in 2008 and 2009 increased at a rate of 10 GW/year. However, the most striking change over the past 10 years was the massive build of natural gas-fired power generation capacity.
In recent years, utilities and independent developers have moved away from natural gas in their planning around new power generation capacity, reflecting uncertainties about fuel supply, natural gas prices and price volatility, environmental regulations, and carbon policy. Increased diversity would make sense to most, and there is a mix of new power generation capacity in development including coal, nuclear, hydro, and natural gas.
However, renewable development projects-–particularly wind and solar— have sprouted up rapidly over the past several years and now dominate the power generation development pipeline (see Figure 6). The total amount of new power generation capacity being planned can overstate the potential for new capacity given the delays and cancellations that occur. For example, in 2000-2001, a large amount of the planned natural gas-fired capacity additions were merchant plants, which subsequently were cancelled.
Renewable project development cancellations jumped to approximately 9 GW in 2009 compared to approximately 1 GW in 2008; so clearly not all of the proposed renewable capacity additions will be built. However, Ventyx expects state-level renewable portfolio standards (RPS) to continue to drive development of wind and solar projects. There is potential for a national RPS requirement and support for large-scale electric transmission expansion, which would further support renewable energy development.
The focus on renewable energy strongly affects the fuel choices for other power generation capacity construction. Wind farms typically require other generating units in a transmission area to ramp up or down to accommodate the wind energy output. As a result, as wind generation capacity expands, more ancillary services and more flexible power generation units are required. Some management at utilities in regions where wind resources are very high has commented that they never might construct another baseload power generation plant. Instead, these utilities most likely will install natural gas-fired simple-cycle and combined-cycle units and are investigating bulk power storage such as pumped hydro and compressed air energy storage.
While the growth in renewable energy is likely to support some amount of additional natural gas-fired power generation capacity, it is not likely that natural gas demand from the power sector will increase as a result of expanding renewable energy. Playing a supporting or “firming” role to renewable energy is important to the grid, but natural gas-fired power plant capacity that is largely operating to support regulation up or regulation down requirements and to meet peak loads will not drive increasing natural gas consumption. Rather, RPS requirements will tend to increase the variability in operation of natural gas units and potentially increase the volatility in natural gas prices. This is good news perhaps for traders and natural gas storage developers, but not much help for shale gas producers that are looking for a steady and reliable market for newly drilled wells.
State, regional, and potential federal regulation of greenhouse gas is another matter. State and regional restrictions on carbon emissions and the potential for federal regulation have created a hostile environment for coal power plant development. Ventyx estimates that since 2005 approximately 80 GW of planned coal-fired power generation capacity was cancelled compared to only 6.5 GW of coal-fired capacity additions. While the regulatory and permitting process has been brutal for new coal plants, there are approximately 4 GW of coal-fired power generation capacity additions currently under construction and expected to come online through 2011. However, the longer-term outlook is less clear.
Ventyx currently assumes that major federal environmental legislation will be passed that will include a national RPS goal of 15-percent renewable energy by 2020 and require power sector CO2 reductions in the range of those outlined in the Waxman-Markey legislation passed by the House in mid-2009. The increasing carbon reduction requirements under such a scenario and the resulting CO2 allowance prices would drive an increasing number of coal plant retirements. However, carbon capture and sequestration (CCS) likely will become commercially feasible around 2020, and through a combination of retirements and retrofits the coal fleet will begin to transform over the 2020 through 2030 time period.
The resulting Ventyx forecast of U.S. power sector demand for coal and natural gas produced varied predictions. Coal consumption will decline as retirements increase around 2020 and despite the assumption of CCS availability, coal demand will be relatively flat after 2025. In contrast, power sector natural gas consumption essentially will be flat through 2020 during the build up of renewable energy to the 2020 RPS goal, but natural gas demand will increase rapidly after that point.
As with any forecast there are uncertainties and alternative assumptions that would alter the forecast results. The near-term outlook for gas demand could be understated if the current push for renewable energy fades. Without a national RPS, renewable energy additions are likely to slow compared to our forecast, and natural gas-fired generation likely would increase. The long-term outlook for gas demand also might be understated, since there’s no guarantee that research and investment to make CCS commercially viable will come to fruition.
The projections above highlight the challenges for natural gas producers: For the next 10 years natural gas demand growth looks weak due to the renewables push and difficulty in dislodging coal-fired power plants without a substantial increase in the price of carbon emissions. For the gas producers that have invested billions to gain premier positions in emerging shale gas plays throughout North America, tepid demand growth over the next decade will make for lean times and potentially affect the level of future investment. Producers focused on higher cost conventional gas production might find their days numbered.
Beyond 2020, natural gas demand requirements are more likely to increase and the increases could be substantial. Gas demand in 2030 might be as much as 20 Bcfd higher compared to current levels, assuming carbon restrictions disadvantage coal post-2020 and renewables penetration slows after reaching the 2020 national RPS standard. Based on current rates of shale gas production growth and robust resource estimates of shale gas in North America, it’s plausible to increase production to supply the incremental natural gas required. The challenge for North American gas producers is doubled, however, because steady declines in conventional gas production also are expected.
The dramatic shift toward shale gas production, ongoing permitting and other regulatory issues, and the uncertain outlook for gas demand growth, have combined to squash expectations for the Alaskan Natural Gas Line and Mackenzie Delta pipeline. These Arctic frontier mega-pipeline projects probably won’t be able to move forward as long as renewables are expanding at their current rate and coal-fired power generation remains viable.
The dramatic emergence of shale gas in the United States has pushed LNG out of focus. However, the global LNG industry continues to expand with approximately 6.3 Bcfd of new liquefaction capacity started up in 2009, and another 4 Bcfd being brought into commercial service this year. While this growth results largely from a wave of new liquefaction projects reaching completion that were planned in response to increases in world natural gas prices several years ago, the global LNG industry likely will see additional waves of expansion after the current down cycle ends.
Several factors likely will result in U.S. LNG imports growing over time—although perhaps not in a way that easily can be planned around. A key driver is the seasonal demand profile in European and Asian markets and vastly smaller underground gas storage capability in these markets. The seasonal demand and lack of storage will result in growing spot LNG imports into the United States. In essence, the United States is expected to play a balancing role in global LNG markets. The result could be more seasonal volatility in U.S. gas prices as a result of events in global gas markets leading to sudden surges or slumps in spot cargoes.
Despite the emergence of shale gas, the outlook for the natural gas industry continues to be heavily dependent on the power sector. While natural gas still might be the bridge fuel, the on-ramp might be a decade away. The 2020 to 2030 time period might become another dash for gas with construction of new natural gas-fired power generation capacity rivaling the merchant boom period. However, this outcome depends on growth in renewables slowing once a 15-percent penetration level is reached and coal-fired power generation coming under pressure as carbon restrictions begin to ramp up.
For the next several years, shale gas producers likely will find they face brutal competition for market share. Assuming the power sector’s focus remains on renewables for the next 10 years, natural gas prices likely will be increasingly volatile but within a fairly narrow range ($5 to $8/MMBtu), with the soft floor set by displacement of higher cost coal-fired power plants and the ceiling based on the marginal cost of conventional natural gas production. After 2020, natural gas prices likely will increase steadily over time with real price escalation driven by increasing demand pressure from the power generation sector.
1. Shale gas wells typically have decline rates upwards of 60 percent after the first year of production, which reflects the high level of stimulation delivered by the hydraulic fracturing process.
2. Gulf Coast LNG values include deliveries to Elba Island facility and exclude deliveries to Freeport LNG, for which there’s currently no timely data. East Coast LNG values exclude certain quantities that don’t move into the interstate pipeline transportation network and include deliveries from the Canaport terminal in New Brunswick, Canada to the U.S. market.