Low Natural Gas Prices Research Articles

LowExTra - Feasibility of a Multi-Conductor District Heating System

District heating (DH) systems can be a promising technology for a low-carbon heat supply if the share of renewable heat and waste heat will be increased. However, the level of integration from low temperature (renewable) heat sources is currently limited by the system temperatures of the heating grid. To develop a solution for this challenge, this paper examines the feasibility of a multi-conductor DH-grid concept which was investigated from technical and economic perspectives. The analysis of the dynamic grid and plant simulations show that a share of over 40 percent renewable and waste heat can be reached in the test area of a built-in district in Berlin. Different designs of the heat supply units lead to similar overall costs and can be competitive compared to decentralized heating concepts with comparably high level of renewable and waste heat. However, in Germany, due to the currently low natural gas price, gas boilers are often still the option with the lowest heat production costs for the existing building stock. Therefore, political action is needed to increase the feasibility for a successful low-carbon transition and to overcome obstacles for innovative low-temperature (LowEx) DH-systems.

US nuclear power: The vanishing low-carbon wedge

Nuclear power holds the potential to make a significant contribution to decarbonizing the US energy system. Whether it could do so in its current form is a critical question: Existing large light water reactors in the United States are under economic pressure from low natural gas prices, and some have already closed. Moreover, because of their great cost and complexity, it appears most unlikely that any new large plants will be built over the next several decades. While advanced reactor designs are sometimes held up as a potential solution to nuclear power’s challenges, our assessment of the advanced fission enterprise suggests that no US design will be commercialized before midcentury. That leaves factory-manufactured, light water small modular reactors (SMRs) as the only option that might be deployed at significant scale in the climate-critical period of the next several decades. We have systematically investigated how a domestic market could develop to support that industry over the next several decades and, in the absence of a dramatic change in the policy environment, have been unable to make a convincing case. Achieving deep decarbonization of the energy system will require a portfolio of every available technology and strategy we can muster. It should be a source of profound concern for all who care about climate change that, for entirely predictable and resolvable reasons, the United States appears set to virtually lose nuclear power, and thus a wedge of reliable and low-carbon energy, over the next few decades.

Microwave Heating-Assisted Catalytic Dry Reforming of Methane to Syngas

Natural gas is a robust and environmentally friendlier alternative to oil resources for energy and chemicals production. However, gas is distributed globally within shales and hydrates, which are generally remote and difficult reserves to produce. The accessibility, transportation, and distribution, therefore, bring major capital costs. With today’s low and foreseen low price of natural gas, conversion of natural gas to higher value-added chemicals is highly sought by industry. Dry reforming of methane (DRM) is a technology pathway to convert two critical greenhouse gas components, CH4 and CO2, to syngas, a commodity chemical feedstock. To date, the challenges of carbon deposition on the catalyst and evolution of secondary gas-phase products have prevented the commercial application of the DRM process. The recent exponential growth of renewable electricity resources, wind and solar power, provides a major opportunity to activate reactions by harnessing low-cost carbon-free energy via microwave-heating. This study takes advantage of differences in dielectric properties of materials to enable selective heating by microwave to create a large thermal gradient between a catalyst surface and the gas phase. Consequently, the reaction kinetics at the higher temperature catalyst surface are promoted while the reactions of lower temperature secondary gas-phase are reduced.

Co-emission and welfare effects of electricity policy and market changes: Results from the EMF 32 model intercomparison project

From the simulation results of the Energy Modeling Forum's recently completed project on US greenhouse gas emission mitigation policies, this paper estimates and examines welfare effects of carbon dioxide (CO2) pricing policies, fuel and technology cost changes, higher electricity demand growth, and limited nuclear generator lifetimes. Eight of the models in the study reported outputs sufficient to estimate damage from CO2, sulfur dioxide (SO2), nitrogen oxides (NOX), and methane, and three of those eight reported outputs sufficient to calculate consumer surplus, supplier profit, government revenue, and therefore total social surplus. Over approximately thirty years, the four CO2 tax policies reduce emissions enough to reduce estimated CO2 damage by $1 to $1.5 trillion, SO2 damage by $1 to $1.3 trillion, and NOX and methane damage by smaller amounts, based on averaging the results from the relevant models. The estimated non-environmental social surplus cost of each of these policies is between 23% and 29% of its environmental benefit. The CO2 cap-and-trade scenario, modeled after the Clean Power Plan, reduces estimated CO2 damage and other emission damage each by $0.4 trillion, at a non-environmental social surplus cost estimated to be 17% of the environmental benefit. Changing the natural gas price changes SO2 damage more than twice as much as it changes CO2 damage. Estimated methane emissions move in the same direction as CO2 emissions in every scenario other than the low natural gas price scenario, in which the methane increase counteracts an estimated 27% of the benefit from the CO2 reduction but only 5% of the total net benefit. In addition, the paper explains the set of assumptions and methods used to estimate environmental damage, and briefly explains how the non-environmental parts of total social surplus can sometimes be computed from more common results if necessary.

Investigation of the price linkage between Asian LNG spot and Far East Asian LNG prices and its implications

For so many times, Far East Asian liquid natural gas (LNG) buyers have been using price linked to crude oil-indexed, now they need to find another alternative pricing formula for their crucial energy supply as a better price structure that could reflect the market is needed. LNG spot price is expected to be the pillar for the future LNG trading, especially for Far East Asia Market. As less and less long-term contracts are signed in the Far East Asia Market, this creates an additional demand for the LNG in the spot market, while it raises some issues about the presence of different LNG pricing mechanisms. Most of the LNG spot prices in Asia are indexed to the relatively low natural gas prices in Atlantic Basin. Furthermore, the advancement of drilling technology in the US drives down its natural gas prices, resulting in price discrepancies between Asian LNG spot and East Asian LNG prices. This study investigates whether there is a price linkage between Asian LNG spot and East Asian LNG prices. This study comprehends 91 observations collected from January 2010 to July 2017. Johansen co-integration tests were carried out to examine the existence of long-run relationship on the spot, Japanese and South Korean LNG prices. The Augmented Dickey-Fuller (ADF), Phillip-Perron (PP), and Kwiatkowski-Phillips-Schmidt-Shin (KPSS) unit root tests were conducted first before proceeding to the co-integration tests. The results showed that Asian LNG spot prices did not have price linkage for monthly averages of Japanese and South Korean LNG prices. The analyses also indicated that Taiwan LNG markets move together with Asian LNG spot markets. As a conclusion, the results inferred that supply dependency on LNG spot cargoes governed the price linkage among these Asian LNG markets. The use of gas indexed LNG price mechanism did not reflect the economic fundamentals in Asia-Pacific Basin.
 JEL Classification: Q41Keywords: Price linkage, Johansen co-integration, augmented Dickey-Fuller, Phillip-Perron, and Kwiatkowski-Phillips-Schmidt-Shin, unit root tests, Far East Asian LNG spot prices, LNG spot and short-term cargoes, long-term contracts, spot prices, energy: demand and supply, prices

The heterogeneous impacts of low natural gas prices on consumers and the environment

We show that low natural gas prices increase gas-fired electricity generation, reduce coal-fired electricity generation, and reduce wholesale electricity prices. However, not all regions experience the same degree of coal-to-gas generation switching or electricity price declines. Specifically, regions experiencing more coal-to-gas switching experience smaller electricity price drops. We provide intuition that may explain this pattern. This finding also has environmental and welfare consequences: coal-fired plants emit more pollutants, and therefore regions that benefit more from greater emissions reductions experience lower benefits from declining electricity prices. The finding highlights a mechanism through which a carbon price would have heterogeneous impacts across regions.

Economics of Coalbed Methane in North West Spain

Coal during its carbonization process produces a gas. This gas, mainly formed by methane, can be used. The use of CBM (Coal bed methane) as an energetic resource is not much known in Spain. This work is the first step to enhance the development of this resource in Castilla y León. A theoretical review and a state of the art description have been carried out, taking into account all the factors that can influence in the development of a CBM project. Then CBM resources have been quantified by Castilla y León accurately for every coal bed. After that, technical feasibility has been used to evaluate total amount of gas that can be recovered. The last step was to evaluate economic feasibility to know how much gas could be economically profitable. This paper covers the economic factor and exploitation options of CBM in Castilla y León, considering technical parameters together with costs and economic requirements for the tow most promising areas in north-west Spain. The main findings include that a CBM system would be feasible in Guardo-Barruelo, however, the economic feasibility will be limited to long operation time of the wells and an increase of the prices of natural gas. In North Leon, the results show a high profitability even under low natural gas prices.

Coal Demand, Market Forces, and US Coal Mine Closures

Economic transitions have the potential to displace workers and cause social unrest. Coal mine closures in the eastern United States due to the changing electricity system and the resulting employment losses in rural areas have become salient issues for all levels of government. Previous research has not distinguished among the potential causes of recent mine closures, such as rising production costs and decreasing coal demand from the electricity sector. This analysis utilizes unique data on coal mine and power plant operation to estimate the impact of supply and demand factors on mine closure. We model closure as a function of expected profits, which allows us to compare the effects on mine closure of specific demand and supply shocks to expected mine profits. Our results suggest that each shock substantially affected coal mine employment. Increasing costs of producing Appalachian coal have had the largest impact on closures with lower natural gas prices and lower electricity demand each accounting for a substantial number of closures additionally.

How much wind and solar are needed to realize emissions benefits from storage?

Environmental outcomes from energy storage depend on its usage patterns, the existing generation fleet, and fossil fuel prices. This work models the deployment of large, non-marginal quantities of energy storage and wind and solar power to determine their combined effects on grid system emissions. Two different grid environments are analyzed: a coal-heavy grid (Midcontinent ISO) and non-coal grid (New York ISO). An iterative dispatch model is used that operates storage to maximize income, considering that this operation can influence wholesale energy prices. With current low natural gas prices ($2.6 per MMBtu), adding storage slightly reduces carbon emissions in New York, while increasing them in the Midcontinent ISO (MISO). Storage increases carbon emissions when it enables a high emissions generator, such as a coal plant, to substitute for a cleaner plant, such as natural gas. We estimate that adding storage operated to maximize revenue in the MISO region will not be carbon neutral until wind or solar power reach around 18% of the generation capacity. Different operation patterns for storage could realize higher carbon reductions. For example, a carbon price on emissions from generators would shift operation to make energy storage carbon neutral even with current wind and solar capacities. Sensitivity analysis shows that a higher natural gas price ($5 per MMBtu) yields much higher storage-induced carbon emissions in both NYISO and MISO and storage in MISO will not be carbon neutral unless 35% of total generation capacity is from wind/solar. This illustrates that low cost, efficient natural gas generation is important to realize emissions reductions with storage under economic arbitrage.

Non-renewable and intermittent renewable energy sources: Friends and foes?

This paper studies the links between non-renewable and intermittent renewable energy sources in the production of electricity. Using U.S. state-level data from 1998 to 2015, we find that the relationship between the price of natural gas and investments in solar and wind capacity is non-linear and can be represented by an inverted U-shape. Hence, for relatively low natural gas prices, the two modes of production are substitutes. After a price threshold is reached, the two are complementary. A theoretical explanation argues that this stylized fact is the result of a trade-off between two characteristics of these modes of production: the high degree of flexibility of electricity production using natural gas as an input and the low marginal cost of renewable energy sources.

Early nuclear retirements in deregulated U.S. markets: Causes, implications and policy options

Electricity prices have fallen significantly since 2008, putting commercial nuclear reactors in the United States under substantial financial pressure. In this market environment driven by persistently low natural gas prices and stagnant electricity demand, we estimate that about two thirds of the 102GW nuclear capacity are uncompetitive over the next few years under the current trajectory. Among those, 18GW are retiring or are merchant plants at high risk of retiring prematurely.The potential consequences of the hypothetical withdrawal of 20GW of nuclear capacity include: 1) a ~3.2% increase in carbon emissions of the power sector if replaced by gas-fired units or 2) a significant increase in cost if replaced by renewables.Without a carbon price, out-of-the-market payments would be needed to effectively maintain merchant nuclear capacity. Filling the revenue gap would come at a fleet-average cost of $3.5–5.5/ MWh for these plants, which is much lower than the cost of subsidizing wind power. The policy support could take the form of direct zero-emission credits, renewable portfolio standard expansion, or clean capacity market mechanisms. As a last resort, the exercise of a new mothballing status could prevent the irreversible retirement of nuclear power assets.

It's All (Mainly) Good: FERC Shows Plentiful Gas Reserves, Low Prices

Overall in 2016 there were record‐low natural gas prices and near‐record‐low electricity prices. Although natural gas production fell for the first time since 2005, flat demand due to above‐average winter temperatures at the start of the year and high natural gas storage inventories contributed to the low prices. The low natural gas prices further incentivized gas‐fired generation in 2016, and for the first time in history, natural gas's share of total electricity generation output overtook coal's on an annual basis.

The growing importance of natural gas as a predictor for retail electricity prices in US

In the literature, there are tests about long and or short Granger causality between primary energy sources such as natural gas and secondary energy sources like electricity. Nevertheless the existence of a causal relationship or not, cannot clearly illustrate the dynamics in their relationship over time. Towards this direction, we apply a one step ahead rolling forecast and examine the performance of the average cost of natural gas as a predictor for retail electricity prices at national and regional level over time. Our analysis answers if, how and when the cost of natural gas becomes a significant predictor of electricity prices. Besides lower natural gas prices, the existence of sufficient gas infrastructures or a competitive market environment or both of them is needed in order to couple retail electricity prices with the cost of natural gas. This growing importance must be taken into account from policy makers by allowing additional gas based stations in the main-grid but at the same time avoiding the risks from the natural gas price volatility.

Presenting the implementation of power-to-gas to an oil refinery as a way to reduce carbon intensity of petroleum fuels

Hydrogen plays a crucial role in refining industry to meet the growing demand and stringent quality of produced gasoline and diesel. Steam methane reforming (SMR) is commonly used by refiners for on-purpose hydrogen production. However, despite being a mature and efficient technology, SMR has a considerable carbon emissions footprint that adds to the carbon intensity of petroleum fuels. Therefore, this paper examines utilizing Ontario province electricity grid that is based mostly on CO2-free sources of electric power to generate hydrogen by electrolysis using the concept of ‘power-to-gas’. Consequently, the study evaluates the deployment of a series of 1 MW nameplate capacity polymer electrolyte membrane (PEM) electrolyzers to produce 25 MMscfd of hydrogen for a refinery, instead of the conventional pathway based on steam methane reforming. It assesses the production costs and life cycle emissions for five production scenarios to meet the hydrogen demand of the refinery. Aspen HYSYS and mixed integer linear programming models are employed for the purpose of this study. Steam methane reforming provides a lower cost hydrogen under low natural gas prices, even with stringent carbon-pricing policy. However, the renewable electrolytic hydrogen production method shows a potential to curb significant carbon emissions from steam methane reforming level, increasing the CO2 free energy and renewable content of the gasoline and design within the life cycle production scheme. This power-to-gas hydrogen production can be compared to eliminating as many as 34,893 gasoline passenger vehicles from the road. Accordingly, supplying electrolytic hydrogen to a refinery by a grid powered from clean energy sources is considered a good venue for providing decarbonization of petroleum fuels.

Going nuclear for climate mitigation: An analysis of the cost effectiveness of preserving existing U.S. nuclear power plants as a carbon avoidance strategy

Nuclear power plants generate over 60% of the carbon-free electricity in the U.S. Due to a decrease in electricity prices as a result of the availability of cheaper natural gas and increased low-cost renewables, many of these plants are at risk of premature retirement. If nuclear power plants retire, CO2 emissions in many U.S. states could increase, even while the states comply with EPA legislation aimed at mitigating emissions of greenhouse gases that contribute to climate change. In this paper, we perform a Monte Carlo-based analysis to determine the breakeven price of electricity these plants must secure in order to avoid financial loses between 2015 and 2040, and find median breakeven electricity prices to range between $35 and $73 per MWh. Based on our estimates of future electricity prices under a low natural gas price scenario from the Energy Information Administration, our analysis suggests that U.S. nuclear plants would require between $8 and $44 per MWh (median results) on top of electric sales revenue in order to breakeven. Assuming natural gas plants would replace retired nuclear power plants, we estimate an equivalent cost of avoided CO2 emissions to be $18-$30 per metric ton of avoided CO2 (median results) for multi-reactor nuclear plants, and $47-$97 per metric ton of avoided CO2 (median results) for single-reactor plants. Preserving the existing nuclear power plant fleet, especially multi-reactor plants, is thus a cost effective carbon-avoidance strategy compared to the social cost of carbon.

Low natural gas prices and the financial cost of ramp rate restrictions at hydroelectric dams

Peaking hydroelectric dams that employ variable, stop-start reservoir releases can have adverse impacts on downstream river ecosystems. Efforts to mitigate these impacts have relied predominantly on the use of ramp rate restrictions, which limit the magnitude of hour-to-hour changes in reservoir discharge. Ramp rate restrictions shift hydropower production towards less valuable off-peak hours, imposing a financial penalty on dam owners that is a function of the “spread” (difference) between peak and off-peak electricity prices. This study examines how low natural gas prices in the U.S. have reduced the cost of implementing ramp rate restrictions at dams by narrowing the peak/off-peak price spread. Significantly lower costs of ramp rate restrictions could open new opportunities for improving environmental flows at dams, including the “purchase” of more natural streamflow patterns by downstream stakeholders, a type of arrangement for which there is growing precedent. We also explore the role that uncertainty in the cost of ramp rate restrictions could play in precluding downstream stakeholders from forming these types of agreements with dam owners. Results suggest that financial “collar” contracts could mostly eliminate inter-annual variability in the net cost of restrictions and provide those purchasing more natural flows with greater certainty.

Are high penetrations of commercial cogeneration good for society?

Low natural gas prices, market reports and evidence from New York State suggest that the number of commercial combined heat and power (CHP) installations in the United States will increase by 2%–9% annually over the next decade. We investigate how increasing commercial CHP penetrations may affect net emissions, the distribution network, and total system energy costs. We constructed an integrated planning and operations model that maximizes owner profit through sizing and operation of CHP on a realistic distribution feeder in New York. We find that a greater penetration of CHP reduces both total system energy costs and network congestion. Commercial buildings often have low and inconsistent heat loads, which can cause low fuel utilization efficiencies, low CHP rates-of-return and diminishing avoided emissions as CHP penetration increases. In the northeast, without policy intervention, a 5% penetration of small commercially owned CHP would increase CO2 emissions by 2% relative to the bulk power grid. Low emission CHP installations can be encouraged with incentives that promote CHP operation only during times of high heat loads. Time-varying rates, such as time-of-day and seasonal rates, are one option and were shown to reduce customer emissions without reducing profits. In contrast, natural gas rate discounts, a common incentive for industrial CHP in some states, can encourage CHP operation during low heat loads and thus increase emissions.

Soft-computing approach to predict cost and performance of natural gas combined cycle (NGCC) plants using carbon dioxide capture

Coal is the backbone of the Indian power sector with more than 60 % of the net installed electricity capacity being coal-based. Among other fossil fuels, natural gas also contributes significantly to the power sector in India. This contribution may increase in the future with exploration of new reserves of unconventional gases, more stringent climate norms and so on. Concurrently, the global climate change problem also becomes more enhanced if larger dependence on fossil fuels remains. In some scenarios, carbon dioxide (CO2) capture and storage (CCS) with natural gas combined cycle (NGCC) may be a feasible technological alternative. Such a scenario is manifested by some critical factors such as low natural gas prices and high carbon tax, among others. Nevertheless, several parameters remain highly uncertain if CCS is to be introduced in NGCC plants. As a result, modern computational techniques such as soft-computing approaches may be used to generate predictive models for cost and performance in such plants. This paper utilizes one such technique, multi-gene genetic programming (MGGP) to generate predictive models for cost of electricity (with coefficient of determination, R2 > 95 %), CO2 emission factor and net plant efficiency (R2 > 98 %). The sensitivity analysis carried out for these parameters show results which are expected in real situations. Subsequently, the calculation of the CO2 avoidance cost and energy penalty for a hypothetical case is demonstrated. The results show that MGGP can be successfully used in such applications.

When Externalities Are Taxed: The Effects and Incidence of Pennsylvania’s Impact Fee on Shale Gas Wells

AbstractTo pay for environmental and public infrastructure costs associated with shale gas wells, Pennsylvania introduced a per-well impact fee despite concerns that it would discourage industry investment. Using a quasi-experimental design and data that nearly cover the universe of leases and wells in Pennsylvania, Ohio, and West Virginia, we find that leasing by energy firms declined dramatically after the fee’s enactment, but little to no declines in well permitting or drilling occurred in the most geologically similar subsample. We estimate that at least 60% of the decline in leasing reflects a liquidity crunch linked to retroactive application of the fee in a time of low natural gas prices. We also observe limited pass-through of the fee to resource owners. Firms could not change the terms of leases signed before the fee, and only half of the fee was passed through in new leases, primarily through a lower royalty rate.

When Externalities are Taxed: The Effects and Incidence of Pennsylvania's Impact Fee on Shale Gas Wells

Drilling in shale formations rich in oil and gas has caused the U.S. to become the global leader in hydrocarbon production, but the growth has come with environmental and public infrastructure costs. States have been slow to introduce taxes to pay for impacts, fearing a decline in drilling-related investment. An exception is Pennsylvania, which introduced a per-well Impact Fee in 2012. Using a difference-in-differences quasi-experimental design and data that nearly cover the universe of leases and wells in Pennsylvania and West Virginia, we find that well drilling, which can require a year or more of preparation, saw modest, if any, declines in the ten months after the Fee's enactment. In contrast, acreage being leased by energy firms declined dramatically. The decline likely reflects a liquidity-crunch caused by retroactive application of the Fee in a time of low natural gas prices and the limited pass-through of the Fee to resource owners. Firms could not change the terms of leases signed before the Fee, and for new leases, we estimate that only half of the Fee was passed to resource owners, 80 percent of which occurred through a lower royalty rate and 20 percent through a lower signing bonus. The findings suggest at least a short-term trade-off between investment and taxes to pay for externalities, even in an industry dependent on a geographically-fixed resource.