By Olga Gorstenko, ZE datawatch
In this issue, we examine aspects that can impact the demand side of U.S. natural gas expansion and ultimately add uncertainty to natural gas price projections.
Natural gas has traditionally served the needs of three major types of customers: manufacturers, power generators, and residents using gas for heating and cooking. The transportation industry now considers expanding the use of natural gas to power automotive vehicles; this creates another avenue for natural gas application.
Among all uses, those for residential customers’ are most predictable. Heating needs are affected largely by seasonal changes in weather (good weather forecasts make it easy to adjust gas supply) and less to the state of economy; hence, the impact of heating on demand for natural gas can be foreseen with more certainty, especially in the long term. Meanwhile, increased use of natural gas by the power industry and manufacturers is driven primarily by economics: the price of gas. The price is not the only factor affecting decisions on expanding its use: power utilities have to consider environmental regulations and other power resources in their generation portfolio, and manufacturers ponder over sustainability of expanding production capacity.
Manufacturers rely heavily on fossil fuels to be used as fuel or feedstock. Currently, low natural gas prices are good news for steelmakers, producers of chemicals, plastics, and fertilizers. In most processes, natural gas can be used interchangeably with oil or coal. When plants can switch between these fuels, at a time of low prices, natural gas becomes a fuel of choice displacing other fossils.
Steelmakers use gas as fuel primarily to fire blast and non-blast furnaces. Switching from coal to natural gas can result in production cost saving of 1-2%. Steel plants have already started replacing coal with natural gas to keep furnaces running. As the last several years have marked a rather dark time for steelmakers, such a turn of events is creating a good incentive, not only to use natural gas as a fuel to improve current financial statements, but also to expand production capacities for longer term benefits.
Natural gas is used as a base feedstock by the chemical industry: more than 80% of chemicals are derived from it. Some fertilizers, such as ammonia-based products, attribute 90% of production cost to natural gas. As a feedstock, natural gas can be switched with crude oil. Users are indifferent to the source of these two fuels when crude is at parity with the price of natural gas in heating equivalent, which happens when the ratio between two prices is maintained at around 7:1. With oil prices floating around $100/Bbl and natural gas not even reaching $4/MMBtu over an extended period of time, no deep financial analysis is needed to see that such a price relation makes natural gas an undisputed favourite.
Increasing profits make manufacturers rise above the simple joy derived from healthy financial statements; nowadays, consideration is being given to expanding production capacities. Lower natural gas prices have been motivating manufacturers to reconsider what became a tendency of closing operations or moving to countries with lower production and labour costs.
Only several years ago, factories, especially in the chemical and fertilizer sectors, joined an exodus to Latin America and South Asia. About 40% of fertilizer production capacity in the U.S. closed down in the first decade of 2000. Now, it seems like we might find ourselves on the brink of a reverse migration as some investors have started demonstrating interest in building more domestic industrial capacity.
- An ammonia facility of 366,000 tons/year of LSB Industries reopened in Pryor, Oklahoma, in 2009. Two more units with projected capacity of 60,000 tons/year at Pryor are under regulatory review.
- Orascom Construction reopened a 250,000 tons/year ammonia plant in Beaumont, Texas.
- A 525,000 tons/year plant in Geismar, Louisiana, by PCS Corporation, is being considered for restarting. The corporation is also reviewing expansion of plants in Lima, Ohio, and Augusta, Georgia.
- CF Industries has revived parts of its Donaldsonville, Louisiana, complex capable of producing more than three million tons/year of ammonia. The company also announced investing up to $60 million to complete an expansion of this facility and $1.5 billion over the next four years to grow its projects in ammonia and other products.
- Methanex Corp. announced plans to move its methanol plant from Chile to Louisiana.
- Santana Textiles LLC decided to build a denim plant in Texas instead of its originally planned destination, Mexico.
Encouraged by government support of shale gas expansion, manufacturers are looking forward to sustained growth in their profit margins. Meanwhile, not everybody in the manufacturing community is on the same playing field. Many remain doubtful that the current trend of low natural gas prices is sustainable. Manufacturers are facing a dilemma: should they capitalize on the current natural gas oversupply and revitalize the abandoned plants in the U.S. (and in many cases move plants back home from international locations), or should they remain on the cautious side and retain what has been very stable, at least from the perspective of costs. Their decision will be based on expectations of whether current low gas prices will be sustained over an extended period of time, and what factors might tilt the current shortage of domestic demand and push prices up.
Disagreement among industrials comes as no surprise — the same events often evoke dissimilar views by different parties leading to a variety or conclusions and courses of action. Thus, some believe that a pending increase in gas exports will lead to growth in the domestic price as a result of equalization with prices in foreign markets (discussed in more details in the July 2012 In-Depth article). Such an increase will diminish benefits for U.S. manufacturers. Those who are certain of this course of events call for government to set restrictions on natural gas exports. Others believe that government interference in the open market can be detrimental, not only from the perspective of creating a case of government meddling with free market forces, but also because reduction in overseas LNG deliveries will affect financial statements and make gas producers unhappy, which will lead to potential cuts in gas production and consequently domestic price increases.
The current state of the market is very favourable to those with gas as a major cost affecting their income statements; however, for longer term investments, especially those involving billions of dollars, the quality of natural gas price projections is of paramount importance. Multiple uncertainties make it very difficult to arrive at a definite conclusion. A lack of clarity creates a looped logic; investment decisions are based on expectations about future natural gas prices, which in their turn are affected by demand being a direct derivative of these decisions.
The power sector is affected by natural gas prices more than any other sector. While being a major influence on the industry as a whole, the impact of prices differs for different types of generators. No doubt, generators that run on natural gas are the first in line to be affected. A rather large number of this type of generator, compared to other types of generators, have been built since the end of the 90’s as a result of deregulation, the relative ease of construction, and of a fast track approval process . Since then, a somewhat excess number of these generators have been used mostly to serve peak hours and to balance real-time fluctuations in demand and support generators with less flexible operation, especially nuclear and renewables.
With low fuel cost, utilities are using more of the natural gas power plants in their generation portfolios and use them more frequently to serve not only as peakers but as baseload-serving units. Low fuel costs are not the only driver of such an increase. Capital costs are significantly lower than those of nuclear plants. According to the EPA, U.S. natural gas-fired generation produces half as much CO2, less than a third as much NOx, and 1% as much SO2 of the average air emissions from coal-fired generation. The growing burden of environmental compliance can be a decisive factor when choosing between these two types of generation sources, with a preference for natural gas-fired generation over those run on coal.
Nuclear power is not a happy player. Some say that the impact shale gas has had on the nuclear industry is almost equivalent to that of the Fukushima incident. Less costly and less risky natural gas-fired power generation, as an alternative to nuclear technology, is offering power utilities better options. However, some believe that over the long-term, at least over the 50-year cycle of their life span, nuclear generators will prove to be more rational for utilities to have in their generation portfolios for two reasons. First, long-term cost expectations are more stable for nuclear units, given a sustained history of high fluctuation of gas prices. Second, even though it is polluting less than coal, natural gas still emits more pollutants than nuclear power. Southern Co. and Scana Corp. took on this perspective in proceeding with the construction of new nuclear power plants. And, they proposed expansion of existing facilities. Southern’s plan to add two new nuclear units at Power’s Plant Vogtle, near Waynesboro, Georgia, was approved by the Nuclear Regulatory Commission (NRC) on February 9, 2012. Scana proposed to build two units at the V.C. Summer nuclear station site near Jenkinsville, South Carolina, which was granted by the NRC with Combined Construction and Operating Licenses on March 30, 2012. Both approvals pave the way for construction of nuclear power generation that has not seen any addition in the U.S. over the last 30 years.
The NRC is currently reviewing applications for nearly twenty nuclear units. Since the NRC review process takes at least four years, utilities will not start construction any time soon. The permits, if granted by the commission, are viewed by utilities as options to be exercised in case natural gas economics change.
Coal power generators, after dominating the power generation base in the U.S. for decades, are facing very difficult times. Being cheap, abundant, and domestic, they once had an overwhelming advantage over other power generation resources. Environmental concerns and deteriorating air quality took precedence over low electricity prices and the many jobs created in mining and transportation. Things have changed and coal generators are losing their competitiveness against natural gas generators. They are losing not only in terms of fuel cost, but also in their capacity to comply with environmental regulation requirements that are becoming more rigorous and strictly regulated. This is rather unfortunate for the coal industry, especially given the fact that coal prices have remained stable over the last couple years as shown in Figure 1 and are expected to maintain low levels in the future as shown in the forward curves in Figure 2.
The EPA has put in a significant amount of effort to reduce damage to the environment from the fossil fuel-run power generators , and especially those fueled by coal. The Cross-State Air Pollution Rule (CSAPR) requiring reduction of NOx emission by 54% and SO2 by 73% from 2005 levels, finalized by EPA in July 2011, has been gone through a series of challenges in courts and requests to delay compliance deadlines. Finally, coal-fueled power generators got a break in August 2012 when the U.S. Court of Appeals for the District of Columbia struck down CSAPR. However, knowing the EPA’s perseverance, we will likely see another version of the rule at some point in the future; but it is yet too early to guess when and with what breadth.
Regardless, even with delayed implementation, compliance requirements are becoming stricter, and upgrades to emission controls so to be in compliance can be prohibitively costly. In wake of a tightening regulatory burden and already existing and mounting costs of environmental compliance, some plants have chosen to shut down their operations. Even though those retirement decisions were reached before the CSAPR was dismissed from the regulatory desk, revised regulation is yet to come and likely will still have a dampening effect on coal power plants.
According to a FERC report, the suite of EPA regulations on electric utility generators could shut down up to 81,000 MW of coal-fired power generation.
The American Electric Power Co., the nation’s largest producer of power from coal, is closing 5 of its 21 coal-powered generators. Dominion Virginia Power announced that is would convert the oldest coal-fired plant, Bremo Power Station, to run on natural gas by 2013. The company has already closed one merchant coal power plant, is planning to retire three old coal plants by 2015 and is converting three small stations to biomass by 2014. Black Hills Power will suspend operations of two coal stations in Colorado and South Dakota by the end of 2012 and another by 2014. To account for the lost capacity, the company is building a natural gas-fired station in Wyoming that will come online in 2014. The companies cited the cost of retrofitting equipment for environmental compliance as the main reason for retirement and conversion.
FirstEnergy Corp. is planning to reduce the number of hours when its coal power station in Ohio, Sammis, is online. After retrofitting the plant with pollution controls for almost $2 billion, the operator cannot compete with the gas-fired units in cost of production.
In the Northwest, low natural gas prices are coupled with the cost of environmental compliance and by wholesale electricity prices that are heavily suppressed by government-subsidized, wind-powered generation. This combination of factors leaves coal-power generation with almost no chance for survival. PPL Montana announced retirement of a Corette power plant in Montana by 2015, and PGE is closing the Boardman plant in Oregon by 2020. Also in 2020, TransAlta will start its staged retirement of Centralia in Washington state.
Carbon capture technologies, as a solution to the coal generators emissions, even though supported by governmental initiatives, do not seem to be getting much traction. On March 27, 2012, EPA proposed a Carbon Pollution Standard for New Power Plants that will apply to fossil-fuel-fired boilers, integrated gasification combined cycle (IGCC) units and stationary combined cycle turbine units that are larger than 25 MW. According to this rule, new coal or petroleum coke-fired units should implement carbon capture and sequestration (CCS). The units can emit 1000 lbs of CO2 per MWh. A generator is permitted to emit more CO2 in the early years as it optimizes the controls over time. While the EPA continues reviewing the proposal, the industry is concerned about whether the pending rule will actually be implemented. With natural gas prices sinking to the lowest level in ten years, there is little incentive for utilities to even consider new plants with the costs weighted down by CCS, especially when the existing plants, coal or gas-fired, are exempt from the requirements.
Even with government support, those few CCS projects targeting coal power generation that are under development in the U.S., are facing difficult times. Out of ten large-scale power plant CCS projects in the U.S., four have been cancelled. Because of the high price tag, ConocoPhillips did not proceed to the second phase of the $4.1 billion Sweeny Gasification Project in Texas, which was expected to support operations of the 680 MW power plant. Tenaska’s Taylorville Energy Center in Illinois, originally intended to cook coal into methane, capture CO2 through CCS and use the methane for 602 MW of power production, has proven to be prohibitively expensive (more than $3 billion), and has been reconsidering plans to abandon the CCS element and retain the gas-fuel technology only for a fraction of the originally estimated total cost. The coal portion of the project is being deferred until gas synthetically derived from goal becomes significantly cheaper than natural gas. The first version of FutureGen, a US government sponsored project originally announced in 2003, was rejected in 2008 on the basis of high costs leading to the DoE retrieving funding. The $1.3 billion FutureGen 2.0 that was announced in 2010 and expected to start in 2015, is already being delayed until 2017.
The Government of Alberta allocated $2 billion to four large-scale CCS projects in 2008 and had one project, Pioneer, cancelled in 2012, which revised Alberta’s investment in CCS to $1.55 billion.
Such economics call into question the commercial viability of other CCS projects for coal-fueled generation, even though there are not so many of them under development.
However, not all utilities are abandoning the coal ships. Quite frequently, power plants have been strategically placed near coal mining sources, which reduce risks associated with transportation and storage. Mine-mouth operation allows the plant to capitalize on the convenience of location and lower fuel costs. Those operators who decide to convert some of the coal units to burn natural gas instead of coal usually choose a reversible conversion, which allows them to switch back to coal when natural gas prices rise. As in the case of nuclear fuel, coal prices are stable throughout the life of supply contracts, which are typically long-term, while natural gas contracts are usually linked to the spot markets. Thus, PacifiCorp is converting its Naughton, Wyoming, coal-fired plant to be run on gas to lower its environmental compliance cost. A similar approach is being considered by the utility for Jim Bridges coal units. The conversion of just a part of the plant to gas-fuelled generator reduces fuel risk; in the case of natural gas price increases, coal might just enjoy a comeback.
Gas will remain the default fuel for power generation as long as gas prices remain low. However, cognizant of the history of natural gas price movements, many power producers remain sceptical that natural gas will sustain these levels over the long term. There is always a chance that it will spike making coal, with all that burden of regulatory compliance, cheaper. On the other hand, if or when federal laws restricting emissions are passed, it will have an impact on all fossil fuel generators. Even though natural gas does not emit as much pollution as coal, it does hold second place after coal in volume of emissions. This will make nuclear technology, which emits almost nothing, more attractive than natural gas.
Another concern is dependence on a transportation infrastructure. A relatively rigid system of gas pipelines with very long lead times for construction and expansion does not allow for any flexibility in cases of transmission disruptions and restricted capacity when demand exceeds supply. These incidents are not just a theory; they have already occurred during winter cold snaps, and their frequency increases. These occurrences even prompted FERC to take on a new initiative and to develop a coordination policy for electricity and natural gas sectors to resolve transportation constraints at times of emergencies.
Similar to manufacturers, some power utilities are not confident about the longevity of the current trend in natural gas prices. Many are hesitant to make bold moves in investing in gas-fired generators on a larger scale. Some participants believe that in the long term, prices of other fuels, such as coal and nuclear, will remain lower than natural gas given the historic profile of these prices. Similar to manufacturing, this creates a causal loop logic in the supply/demand balance.
Natural Gas Vehicles (NGV)
Transportation is an area that the natural gas glut might affect most. High oil prices, a natural gas production boom and government support make this fuel option very attractive and create a potential to change the whole landscape of the industry. Aside from being cheaper in heating equivalent at the current state of markets, gas emits about 25%-30% less CO2 than petroleum or diesel.
Natural gas can be used in several ways to power engines. Compressed natural gas (CNG) and LNG are a direct form of natural gas used as a fuel. Indirect approaches are also possible when gas is converted to liquid (GTL) for engines or power for electric vehicles. GTL requires heat and chemistry to convert gas into liquid, like diesel or kerosene. As oil prices are soaring, the expansion of GTL is increasing.
Most NGVs introduced to the market have been targeting industrial, construction and other heavy-duty applications. Ford has been manufacturing NGVs for the last three years. Chrysler just started manufacturing the CNG Ram 2500 heavy duty pickup. The vehicle has duel fuelling options, CNG, which is used as the primary fuel alternates automatically with gasoline. GM is planning to start releasing two pickups in late 2012, Chevrolet Silverado and GMC Sierra 2500 HD, both will run on CNG and petroleum. The only light NGV version is offered by Honda; its Civic has been produced over the last 14 years and sold primarily as a fleet car.
While the prospect of NGV seems promising and has support from environmentalists, this technology is incorporated in less than 1% of all vehicles. The application of natural gas as a transportation fuel is restricted (3% of produced natural gas is used by transportation), and there are many issues associated with a gas-fuelled vehicle.
The major stumbling blocks in the way of NGV expansion have to do with technological aspects, costs, and refuelling infrastructure. CNG has to be stored under pressure, which makes the fuel tank significantly larger than that used for gasoline. Vehicles have to be retrofitted to accommodate gas as a fuel and this is rather expensive. Vehicle retrofitting increases the cost by $20k in the case of Ram and in the Civic by $10k.
The fuelling infrastructure is limited as shown in Figure 3; that’s why the use of NGV has been mainly restricted to centralized fleets, such as trucks, buses and heavy duty vehicles. More than half of the CNG fuel stations are privately owned.
Many municipalities operate NGV bus fleets. Dallas-Fort worth airport has a fleet of maintenance vehicles run on gas. AT&T is planning to build the largest CNG vehicle fleet. One of the solutions to resolve the refuelling conundrum is proposed by Clean Energy Fuels, an initiative by T. Boone Pickens, which promises to establish NG fuelling options at truck stops nation-wide.
The hope that this sector will grow rests primarily on government incentives. A new tax incentive is being considered by the Obama administration to support the use of natural gas in commercial vehicles and to build up the re-fuelling infrastructure. If approved by Congress, it might just do the trick by lowering the cost of production and increasing demand. The State Natural Gas Act of 2012, currently being reviewed in the senate, promotes the use of natural gas as a transportation fuel, as well as public and private investment in natural gas vehicles and the associated transportation infrastructure. The proposed legislature covers the whole cycle of NGV, from the production of vehicles to their purchase and fuel costs. The act calls for $100 million in grants to build a refuelling infrastructure, and increase the existing $7,500 tax credit to $10,000 for NG-run automobiles and heavy-duty and medium vehicles through 2016.
As in most cases of government subsidies, there are unhappy and happy parties. No doubt, not all taxpayers are pleased with the prospect of supporting this initiative. Manufacturers, electricity and natural gas users are seen as losing parties in this arrangement with money being directed towards expansion of only one sector, thus leading to a distorted increase in demand. This might just impact competitiveness and put a cost pressure on manufacturing and electricity industries.
Ever since the U.S. natural gas industry was opened to competition, high volatility of natural gas prices has remained steady. Unexpected natural gas price fluctuations have been caused mostly by weather, natural disasters, and transportation disruptions. At the same time, a closed system of pipelines with known capacities and demand projections that are developed and updated on an ongoing basis by government agencies have been leaving not much room for guesswork. Still, with not so many inputs, price forecasts have proven to be a difficult task; forward curves developed on exchange-traded futures have not been following spot prices accurately. Analysts, risk managers, and decision makers found it difficult to predict market movements.
Now we are facing even more challenging times. An increase in natural gas supplies, boosted by expansion of shale plays exploration, poses more questions and creates more uncertainty for those businesses and industries that rely on natural gas for their operations. In some cases uncertainty contributes to changes in supply of shale gas, and in other cases it affects demand for the growing volume of this fuel.
The U.S. government sees natural gas expansion from shale plays as a solution for achieving energy independence that it has sought for 40 years. However, government support alone will not determine the future of the natural gas supply, the need for more natural gas is affected by many factors. The major driver of accelerating demand is the degree to which it can be exported in a liquefied form, LNG. This venture, so attractive for gas producers, faces growing opposition from those who believe that exports will exhaust supplies sooner and push domestic prices up. Calls for imposing government control over volumes of LNG exports are getting louder in Congress. If government control is imposed, it will have a dampening effect on gas production.
Aside from potential restrictions imposed on gas supply, the global nature of LNG has its own constrains and concerns. Given that the primary target buyers in Asia are remote markets, U.S. natural gas will remain competitive globally if its production is cost efficient. Global prices, unpredictable political events and shifts in LNG trading patterns have to be examined closely to avoid over or under production, as well as to ensure that trade partnerships remain profitable. As well, the cost of production, which encompasses several components (delivery, liquefaction, shipping, storage and regasification), infrastructure and the rate at which LNG terminals are being constructed also affect the volume of LNG exports.
Another source of growing demand for natural gas is its use as an alternative fuel by the transportation industry.
The popularity of vehicles fueled by natural gas in its condensed or liquefied form is growing; however, costs for these vehicles remain high. Besides, the expansion of natural gas-fueled vehicles is restricted by a limited infrastructure of filling stations. An inherently high cost of retrofitting, as well as a lack filling infrastructure, can be offset by government subsidies. Moreover, the use of natural gas as a transportation fuel is primarily driven by the cost of petroleum, which currently remains high. But, will the oil stay expensive forever? Crude oil price projections, with multiple factors and shortage of publicly available information, are a topic for a separate analytical research.
Some manufacturers and power industry representatives are looking at cheap gas as a panacea; however, a long history of price volatility keeps many of them hesitant to expand production capacities fueled by natural gas.
Shale gas production itself faces constraints and uncertainties. Reserve estimations prepared by different parties, government and industry, differ dramatically and have been questioned and criticized by opposing sides. As uncertainty remains about actual reserves, the cost and rate of production can be affected by applied technologies and cost of compliance with regulations on fracturing.
To cap it all, environmental regulations, those in effect and in the making, as well as those being considered, will affect both sides of the equation. Depending on which are approved and implemented, the power generation mix, natural gas recovery, and use of natural gas as an alternative fuel can be altered dramatically and shifting input parameters into unknown territory.
It is not so easy to predict the expanse and direction of the future of natural gas use given the interrelationship of future price movements by market participants, investments in natural gas-supported sectors, and government subsidies for the industry. For now, these are the factors arising from shale gas expansion that have or might have an impact on natural gas prices.