Demand/Supply for Natural Gas and LNG 2005-2020

Introduction

The combination of secure energy supplies, higher natural gas prices, lower LNG production costs, rising gas import demand, with an increasing demand for clean energy in the developed and developing world, and the desire of gas producers to monetize their gas reserves, is setting the stage for increased LNG trade in the years ahead.

Expected gas supply gaps in the USA, UK, mainland Europe and China, and continued demands in the Asia-Pacific region make LNG an increasingly attractive prospect for supplying energy to these growing markets.

The demand for primary energy is growing at 2.9% annually, on the back of global economic recovery and the ongoing boom in China. Oil consumption is growing at 2.1%, above the 10 - Year annual average growth rate of 1.6% with natural gas demand growing at 3.0% and LNG demand growing at 8% to 10%.

With the demand for natural gas growing faster than for oil; “Natural gas will overtake oil in providing primary energy – equivalent consumption as early as 2025 with

LNG market demand reaching 500 Mtpa (million tonnes per annum) in 2030” (C Watson SHELL, September 10th 2003), LNG together with foreign pipeline gas may well be the answer to many energy shortfalls?

With the development of new technology and attractive pricing, LNG facilities are playing a key role in meeting the long term energy needs. The simple and safe ability to liquefy natural gas, ship it around the world and regasify where the markets are means that it has become more affordable and convenient; as such natural gas is now known as ‘fuel of choice’.

Table 1

For example, the largest market for natural gas, as a primary fuel, whether in natural or liquid format (LNG), is electrical power generation.

The tabulation (see Table 1) explains why.

Demand for global LNG has grown from the first 260 Mcfd (million cubic feet/day) commercial LNG export plant in Arzew, Algeria in the early 1960’s to a forecasted demand of 200 Mtpa (million tonnes/annum) in 2008 as illustrated below. This demand is expected to reach 450 Mtpa by 2020.

Natural Gas Reserves

The worldwide community consumes approximately 2.6 Tcm (trillion cubic meters) of natural gas each year. Fortunately, natural gas is a resource found in significant volumes worldwide. At the end of 2003, according to BP Statistical review of World Energy June 2004, the world’s known and proven natural gas reserves were estimated at about 176 Tcm, roughly 60 times the volume of gas consumed in that year and clear evident that despite the world’s appetite for its “fuel of choice” natural gas: exploration and development efforts have more than met demand.

However, as with crude oil, the distribution of the world’s supply of natural gas is not congruent with patterns of demand. Countries having large gas reserves and low gas demand generally seek to monetize their gas (convert it from a natural resource into a saleable product). If there is no high value gas market within a reasonable and safe pipeline distance, liquefaction of natural gas (LNG) becomes one serious option for achieving this goal.

However the estimated total remaining worldwide gas reserves and resources are considerable larger at 275 Tcm an increase of 56% on known reserves, with Russia holding the largest share. A large part of the worldwide gas reserves is classified as “low risk” gas, located in the Middle East and other moderately remote areas. The remainder of reserves is “higher risk or stranded” either located in “technologically challenging” (usually deep onshore or deepwater) reservoirs or in remote regions, especially polar regions.

The leading countries producing natural gas and selling it to world markets in the form of LNG have seen these exports rise by 6.5%/year since 1980 from 27.74 Mtpa to 129 Mtpa. LNG is the world’s fastest growing fuel.

The chart above summarizes:

•  Proven reserves at 176 Tcm

•  Undiscovered natural gas at 120 Tcm

•  Stranded reserves at 85 Tcm*

•  Reserve growth at 66 Tcm*

On January 1, 2004, worldwide proven reserves of natural gas were 176 Tcm, an increase of 10% more than the estimate for 2003. Some of those natural gas reserves is stranded a long way from the consumer markets in countries that do not need large quantities of primary energy.

Over the next 30 years the natural gas sector will require investments of $3 trillion or $105 billion per year split 50:50 between exploration and gas field development and production. This funding will double present production capacity with the 30 member countries of OECD (Organisation for Economic Co-Operation and Development) accounting for 50% of the investment.

The transmission and distribution networks, underground storage and

LNG facilities required to bring the natural gas to market, will require an additional investment of $1.4 trillion.

LNG production will require of more than $39billion over the next five years. This investment will be spent on production plants, carriers and import re-gasification terminals.

Worldwide production of natural gas currently at 2.6 Tcm/year is expected to rise 4.8 Tcm/year by 2025 an average increase of 2.75%/year.

United States - Natural Gas Demand and Supply

The following forecast of U.S. natural gas demand was prepared by the Energy Information Administration of the Department of Energy.

Projected Increases in Natural Gas Use Are Led by Electricity Generators 

In the Annual Energy Outlook (AEO) 2005 reference case, total natural gas consumption increases from 22.0 trillion cubic feet in 2003 to 30.7 trillion cubic feet in 2025. In the electric power sector, natural gas consumption increases from 5.0 trillion cubic feet in 2003 to 9.4 trillion cubic feet in 2025 (Figure 82), accounting for 31 percent of total demand for natural gas in 2025 as compared with 23 percent in 2003. The increase in natural gas consumption for electricity generation results from both the construction of new gas-fired generating plants and higher capacity utilization at existing plants. Most new electricity generation capacity is expected to be fueled by natural gas, because natural-gas-fired generators are projected to have advantages over coal-fired generators that include lower capital costs, higher fuel efficiency, shorter construction lead times, and lower emissions. Toward the end of the forecast, however, when natural gas prices rise substantially, coal-fired power plants are expected to be competitive for new capacity additions. 

Industrial consumption of natural gas, including lease and plant fuel, is projected to increase from 8.1 trillion cubic feet in 2003 to 10.3 trillion cubic feet in 2025. Although increases are projected for most industrial sectors, decreases are expected in the iron, steel, and aluminum industries. The industrial sectors with the largest projected increases in natural gas consumption growth from 2003 through 2025 include metal-based durables, petroleum refining, bulk chemicals, and food. Natural gas use is also projected to increase in the residential sector by 0.7 percent per year and in the commercial sector 1.2 percent per year on average from 2003 to 2025. 

Unconventional Production Becomes the Largest Source of U.S. Gas Supply 

As a result of technological improvements and rising natural gas prices, natural gas production from relatively abundant unconventional sources (tight sands, shale, and coal-bed methane) is projected to increase more rapidly than conventional production. Lower 48 unconventional gas production grows from 6.6 trillion cubic feet in 2003 to 8.6 trillion cubic feet in 2025 (Figure 83) and from 35 percent of total lower 48 production in 2003 to 44 percent in 2025. 

Production of lower 48 non-associated (NA) conventional natural gas declines from 9.5 trillion cubic feet in 2003 to 8.6 trillion cubic feet in 2025, as resource depletion causes exploration and development costs to increase. Offshore NA natural gas production is projected to rise slowly to a peak of 3.9 trillion cubic feet in 2008, then decline to 3.6 trillion cubic feet in 2025. 

Production of associated-dissolved (AD) natural gas from lower 48 crude oil reserves is projected to increase from 2.5 trillion cubic feet in 2003 to 3.1 trillion cubic feet in 2010 due to a projected increase in offshore AD gas production [139]. After 2010, both onshore and offshore AD gas production are projected to decline, and total lower 48 AD gas production falls to 2.4 trillion cubic feet in 2025. 

The North Slope Alaska natural gas pipeline is projected to begin transporting Alaskan gas to the lower 48 States in 2016. In 2025, total Alaskan gas production is projected to be 2.2 trillion cubic feet in the reference case, compared with 0.4 trillion cubic feet in 2003. 

Growing Production Is Expected from the Rocky Mountain Region 

In the reference case, total natural gas supplies are projected to grow by 8.2 trillion cubic feet from 2003 to 2025. Domestic natural gas production is expected to account for 34 percent of the total growth in gas supply, and net imports are projected to account for the remaining 66 percent. 

Over the forecast period, the largest increase in lower 48 onshore natural gas production is projected to come from the Rocky Mountain region, primarily from unconventional gas deposits. Rocky Mountain natural gas production is projected to increase from 3.7 trillion cubic feet in 2003 to 5.6 trillion cubic feet in 2025 (Figure 84). In 2003, Rocky Mountain production was 27 percent of total lower 48 onshore production. The Rocky Mountain region’s share of lower 48 onshore production is projected to increase to 38 percent in 2025. The only other increases in production are expected in the Northeast and Southwest regions. In the Northeast, production rises from 900 billion cubic feet in 2003 to 1.2 trillion cubic feet in 2019 and declines slightly thereafter. In the Southwest, production rises from 1.7 trillion cubic feet in 2003 to 2.4 trillion cubic feet in 2018 and declines to 2.1 trillion cubic feet in 2025. 

Natural gas production in the onshore Gulf Coast and Mid-continent regions remains relatively constant through 2011, then declines to 3.8 and 1.9 trillion cubic feet, respectively, in 2025. West Coast production declines throughout the forecast. Regional declines in the projections reflect depletion of the natural gas resource base and increasing costs of gas exploration and development in those regions. 

Net Imports of Natural Gas Grow in the Projections 

Net imports of natural gas make up the difference between U.S. production and consumption. Imports are expected to be priced competitively with domestic sources. Supplies of natural gas from overseas sources account for most of the projected increase in net imports in the reference case (Figure 85). New LNG terminals are projected to start coming into operation in 2006, and net LNG imports increase to 6.4 trillion cubic feet in 2025. 

Net imports of natural gas from Canada are projected to decline from 3.0 trillion cubic feet in 2005 to 2.5 trillion cubic feet in 2009, rise again to 3.0 trillion cubic feet in 2015, and then decline to 2.5 trillion cubic feet in 2025. A steady decline of conventional production in the Western Sedimentary Basin is more than offset by increases in unconventional production in western Canada, conventional production in the MacKenzie Delta and Eastern Canada, and LNG imports. Although a MacKenzie Delta natural gas pipeline is expected to open in 2010, pipeline imports from Canada decline at the end of the forecast, because Canada’s gas consumption increases more rapidly than its production. 

Mexico has considerable natural gas resources, but the United States historically has been a net exporter of gas to Mexico, where industrial consumers along the border are closer to U.S. supplies than they are to domestic supplies. In the reference case, net U.S. exports to Mexico are projected to increase through 2006, when an LNG import terminal in Baja California, Mexico, begins exporting natural gas from western Mexico to the United States. 

Delivered Prices Follow Projected Trends in Wellhead Prices 

 Trends in delivered natural gas prices largely reflect changes in wellhead prices. Wellhead natural gas prices are projected to decline in the early years of the AEO2005 reference case forecast, as drilling levels increase, new production capacity comes on line, and LNG imports increase in response to current high prices. As a result, end-use delivered prices are projected to fall (Figure 86). After 2011, however, both wellhead and delivered natural gas prices are projected to increase in response to the higher exploration and development costs associated with smaller and deeper gas deposits in the remaining domestic gas resource base. 

Transmission and distribution margins in the end-use sectors reflect both the volumes of gas delivered and the infrastructure arrangements of the sectors. The industrial and electricity generation sectors have the lowest end-use prices, because they receive most of their natural gas directly from interstate pipelines, avoiding local distribution charges. In addition, summer-peaking electric generators reduce transmission costs by using interruptible transportation rates during the summer, when there is spare pipeline capacity. As power generators take a larger share of the natural gas market, however, they are expected to rely more on higher cost firm transportation service.  

On average, transmission and distribution margins are projected to remain relatively constant in the forecast, because the cost of new facilities largely offset the reduced depreciation expenses of existing facilities. If public opposition prevented the building of new infrastructure, delivered prices could be higher than projected in the reference case. 

Technology Advances Could Moderate Future Natural Gas Prices 

In the reference case, average lower 48 wellhead natural gas prices are projected to decline from the 2004 level to $3.64 per thousand cubic feet (2003 dollars) in 2010 and then increase to $4.79 per thousand cubic feet in 2025 (Figure 87). Technically recoverable natural gas resources (Table 28) are expected to be adequate to support projected production increases. As lower 48 conventional natural gas resources are depleted and wellhead prices rise, an increasing proportion of U.S. natural gas supply is projected to come from Alaska, unconventional production, and LNG imports. 

In the slow oil and gas technology case, advances in exploration and production technologies are assumed to be 50 percent slower than those assumed in the reference case, which are based on historical rates. As a result, natural gas development costs are higher, wellhead prices are higher ($5.18 per thousand cubic feet in 2025), natural gas consumption is reduced, and LNG imports increase. 

The rapid technology case assumes 50 percent faster technology progress than in the reference case, resulting in lower development costs, lower wellhead prices ($4.35 per thousand cubic feet in 2025), increased consumption of natural gas, and lower LNG imports than are projected in the reference case. 

Natural Gas Supply Projections Reflect Technological Progress Rates 

Because the impacts of technological progress are cumulative, the rapid and slow technology cases diverge increasingly from the reference case in the later years of the forecast (Figure 88). In the reference case, lower 48 natural gas production is projected to total 19.6 trillion cubic feet in 2025. The corresponding projections are 22.5 trillion cubic feet in the rapid oil and gas technology case and 17.4 trillion cubic feet in the slow technology case. 

The cost-reducing effects of rapid technological progress primarily affect the economic recoverability of the unconventional resource base, because there are more opportunities for technological improvement in the exploration and recovery of unconventional gas than there are for conventional gas. In 2025, unconventional gas production is projected to be 11.0 trillion cubic feet in the rapid technology case and 7.1 trillion cubic feet in the slow technology case, compared with 8.6 trillion cubic feet in the reference case. 

The rate of technological progress also affects the contributions of other natural gas supply sources. Because rapid progress is projected to increase the rate of production of lower 48 natural gas resources and reduce wellhead prices, both the Alaska gas pipeline and new LNG terminals are less viable economically in the rapid technology case than in the reference case, and their construction is delayed. In the slow technology case, more LNG terminal capacity is projected to be built, and the Alaska gas pipeline and some LNG terminals are projected to be built earlier. Projected LNG imports in 2025 total 5.7 trillion cubic feet, in the rapid technology case and 6.8 trillion cubic feet in the slow technology case. 

Rapid Technology Assumptions Raise Natural Gas Reserve Projections

Natural gas wellhead productive capacity directly reflects reserve levels. The AEO2005 projections for lower 48 natural gas reserves are based on expected levels of natural gas exploration and development drilling resulting from projected cash flows and profitability. In the reference case, lower 48 reserves grow to 207 trillion cubic feet in 2008, then decline slowly to 178 trillion cubic feet in 2025 (Figure 89). 

In the rapid technology case, the finding and success rates for gas well drilling are higher than in the reference case, and exploration and development costs are reduced, resulting in more drilling activity and reserve additions. In this case, lower 48 reserves are projected to peak at 215 trillion cubic feet in 2009, then decline to 205 trillion cubic feet in 2025. 

In the slow technology case, finding and success rates are lower, exploration and development costs are higher, and drilling activity and reserve additions are lower than projected in the reference case. Lower 48 reserves are projected to peak at 200 trillion cubic feet in 2008, then decline to 159 trillion cubic feet in 2025. 

In all three cases, the natural gas resource base is sufficient in the early years of the forecast to support the increases in drilling activity and reserve additions that are stimulated by higher projected prices. As a result, reserve additions early in the forecast generally exceed production. In later years, resource depletion reduces reserve additions per well, and rising costs of gas well development reduce drilling activity. As a result, production generally exceeds reserve additions, causing total reserves to decline toward the end of the forecast. 

Forecast Comparisons

Natural Gas

There are considerable differences among published forecasts of natural gas prices, production, consumption, and imports (Table 36). The differences highlight the uncertainty of future market trends. Because the forecasts depend heavily on the underlying assumptions that shape them, the assumptions made in each forecast should be considered when different projections are compared.

Over the period from 2007 to 2025, the AEO2005 reference case is within the range of projections for total natural gas consumption in the other forecasts. The lowest projected totals for natural gas consumption in 2025 are from the DB forecast, and the highest are from the EVA forecast. For residential and commercial natural gas consumption, DB projects the strongest growth from 2003 to 2025, and the GII forecast has the lowest projected consumption levels. The AEO2005 reference case projections for 2025 fall in the high end of the range for residential consumption and in the mid-range for commercial consumption.

Natural gas consumption in the industrial and electric power sectors is more difficult to compare, given potential definitional differences. The EVA forecast shows the fastest growth in natural gas consumption from 2003 to 2025 in combined totals for the industrial and electric power sectors, whereas the DB forecast shows much slower growth than the other forecasts.

Natural gas for domestic consumption is supplied by domestic production and net imports. All forecasts show domestic production providing a decreasing share of total natural gas supply. The Altos forecast shows a smaller shift in that direction, with significantly lower net imports and significantly higher domestic production. Three of the forecasts—AEO-2005 reference case, GII, and DB—project that net imports will supply about 30 percent of end-use consumption by 2025. EVA projects that 36 percent of consumption will be supplied by net imports, Strategic Energy & Economic Research, Incorporated (SEER) projects 26 percent, and Altos 18 percent (for Altos, the percentage is calculated as net imports divided by the sum of production and net imports).

The volume of net imports varies significantly among the forecasts, as does the mix of net imports. GII, SEER, and Altos expect a decline in net pipeline imports of more than 50 percent between 2003 and 2025, the AEO2005 reference case projects a more modest decline of about 20 percent, and EVA anticipates an increase in net pipeline imports of 30 percent (DB is not included in this comparison because of definitional differences). All the forecasts project strong growth in LNG imports, with net LNG imports in 2025 ranging from 4.6 trillion cubic feet in the Altos forecast to 8.3 trillion cubic feet in the EVA forecast (again, DB is excluded from this comparison). The AEO2005 reference case is more conservative than most of the forecasts for LNG imports: GII, EVA, and SEER all project higher levels of LNG imports in 2025 than are projected in the AEO2005 reference case. Wellhead natural gas price projections for 2025 in the AEO2005 reference case are higher than those in all the other available forecasts, with the exception of Altos.

Wellhead natural gas prices in the EEA and PIRA forecasts exceed those in the AEO2005 reference case in 2015. Of the three forecasts that project end-use prices for 2025 (AEO2005, GII, and SEER), SEER shows the highest end-use-to-wellhead margins for the electric power sector, and the AEO2005 reference case shows the lowest end-use-to-wellhead margins for the industrial sector. For the residential and commercial sectors, the projected margins in the AEO2005 reference case fall between GII on the low end and SEER on the high end of the available forecasts. Industrial sector margins are notably lower in the AEO2005 reference case than in the other forecasts, and electric power sector margins are notably lower in the GII forecast (where some of the differences may reflect definitional variations) than in the other forecasts.

LNG Demand

1.  World Demand

Three recent forecasts project the worldwide demand for LNG to almost double by 2010 to over 250 million metric tons (mmt).  By 2015, they project a demand that ranges from 370 mmt to 428 mmt.   The Exxon Mobil forecast for 2020 is 450 mmt.

                                                                  WORLD LNG DEMAND

                                                                        Millions of Tonnes

                                                         2004         2010        2015          2020                                    

Citigroup (Oct. 05)                             129           264         428

Exxon Mobil (Apr. 05)                                          255         370           450

Poten & Partners, Inc. (June 05)                        250

Citigroup expects about 38% of the growth to 264 million metric tons in 2010 to occur in the U.S. or about 51 mmt. They believe consumption is “surging” in Europe, while China and India will contribute to the expected increase in demand.  

The Exxon Mobil LNG demand forecast is more conservative than Citigroup.  Their demand distribution by region for 2010 and 2020 is shown below.

                                                                Million of Tons                    

                                                2004                2010                2020                   

Asia-Pacific                                86                   120                190

Europe                                        29                     80                130

North America                            14                     55                130

Total                                          129                   255                450

Japan is currently the largest importer of LNG with 24 import/regasification facilities.  In 2004 they imported 56 mmt of LNG, 65% of the regions imports and 43% of the world demand.  LNG accounts for 90% of the gas supply in Japan and Taiwan and all of the gas supply in South Korea.  However, the growth rate of LNG imports to Japan over the next 10-20 years is expected to be small, 1-2% per year. 

China is likely to become a major LNG importer according to the USEIA which projects the gap between domestic natural gas production and demand in 2020 to be approximately 200 billion cubic meters, 7 trillion cubic feet.   If all of the 7 trillion cubic feet gap was filled by LNG imports that would equal 143 million metric tons.   Although Exxon Mobil did not provide a breakdown of their Asia Pacific forecast by country it is very likely, in light of the ABARE projections, that the amount included for China is nowhere near 143 mmt.    LNG imports to India are also projected to grow very rapidly.

In June 2005, the Australian Bureau of Agricultural and Resource Economics (ABARE) published a report, “The Asia Pacific LNG Market: Issues and Outlook.”  The report included these LNG import projections for 2015.

                                                2004                2015
                                               million of metric tons

Japan                                      55.8                   61

South Korea                            21.6                  33

Taiwan                                      6.6                  12

India                                          1.9                  15

China                                           0                  18

2.  U.S. Demand

U.S. LNG imports in 2004 increased to 13.4 million metric tons from 9 mmt in 2003.   As noted above, Citigroup expected U.S. imports to increase by 51 mmt between 2004 and 2010 to a total of 64 mmt which is higher than the highest EIA forecast of 55 mmt.  The EIA projections for 2010 range from 43 to 55 mmt.  Other demand projections are shown in the table below for 2015 and range from 78 mmt to109 mmt; and for 2025 from 124 mmt to 170 mmt. 

These U.S. projections are based on the Energy Information Administration (EIA) Annual Energy Outlook 2005 data presented in table 36. The values for LNG imports were given in trillion cubic feet and converted to tonnes of LNG by using a factor of 1 trillion cubic feet equals 20.53 million metric tons.

                                                                 U.S. LNG DEMAND

                                                                    (millions of tons)

                                                    2003      2010      2015      2020       2025             

EIA AEO 2005 (Ref. Case)           9            51            89       114        131              

                          (High Case)                       55            98       122        143              

                          (Low Case)                        43            78       110        124              

GII (Summer 04)                                                        109                     154

EEA (Oct. 04)                                                             103                      NA

EVA (Aug. 04)                                                            106                     170

PIRA (Oct. 04)                                                            105                      NA

SEER                                                                           87                      134

Altos (Sept. 04)                                                            95                       NA

GII, Global Insight, Inc

EEA, Energy and Environmental Analysts, Inc.

EVA, Energy Ventures Analysis, Inc.

PIRA, PIRA Energy Group

Altos, Altos North American Regional Gas Model, Base Case

LNG Supply

The table below shows world LNG exports and imports by country of origin in 2004.  A total of 178 billion cubic meters (6.3 trillion cubic feet or 129 million metric tons) of LNG was exported in 2004.  The major suppliers were Indonesia, Algeria, Malaysia, and Qatar.  The next largest suppliers were Trinidad & Tobago, Nigeria, and Australia. Oman, UAE, and Brunei were also large suppliers.  The U.S. shipped 1.7 billion cubic meters to Japan from the LNG liquefaction facility in Alaska.

The tables above show 2004 LNG exports and imports by region and country and the % change from 2003.  Worldwide LNG exports in 2004 increased 6.2% over 2003.  Among exporting countries, Malaysia, Australia, Qatar and Trinidad experienced double digit growth in 2004.

India appears as an importer in 2004 for the first time while China, expected to be a major LNG importer is not yet importing any LNG. U.S. 2004 imports increased 29% over 2003.

Exxon Mobil 2005 forecast of LNG supply by region is shown in the following table.

(Millions of Tons)