Introduction
Methodology
To analyze the economics of 4,000 MW-scale pipeline and HVDC transmission options, we developed two spreadsheet models focusing on costs and profit/loss We examined nine scenarios for delivering wholesale electricity to Chicago, comprising six scenarios with a hydrogen pipeline and three utilizing HVDC power lines All scenarios are based on the year 2010, incorporating anticipated technology cost reductions from current expenses.
1 A 1000-mile, 36-inch pipeline with low-pressure electrolyzers and separate compressors;
2 A 1000-mile, 36-inch pipeline with high pressure (1,000 psi output) electrolyzers and no external compression; and
3 A 1000-mile, 18-inch pipeline with high pressure (1,000 psi output) electrolyzers and no external compression 13
For comprehensive information on "zero-emissions" concepts related to coal and other carbon fuels, visit resources such as the U.S Department of Energy's NETL site, Clean Energy Systems, Lawrence Livermore National Laboratory, ZEST, and ZECA These platforms provide valuable insights and updates on advancements in clean energy technologies and carbon reduction strategies.
Both pipelines and HVDC systems can be easily paralleled and expanded to meet regional transmission capacity needs This flexibility significantly influences pipeline dimensions, the economics of transmission, and the selection of transmission methods.
Each of these pipeline scenarios is explored with two types of hydrogen-fueled electricity generation in Chicago (yielding the six scenarios):
1 A solid oxide fuel cell (SOFC) with a gas turbine operating on byproduct heat, and
2 A combined cycle combustion turbine (CCCT).
The HVDC scenarios developed for modeling purposes are:
1 Two full HVDC systems, including lines and converters, 2,000 MW each, installed on two sets of towers;
2 The same two systems installed on one set of towers; and
3 The same two systems installed on one set of towers, with the final 100 miles into Chicago installed underground
The cost model aggregates capital and operating costs from various literature and industry sources, with detailed scenario costs outlined in Chapter 2 In contrast, the revenue model is more intricate, utilizing actual hourly wind generation data from 1999 for both pipeline and HVDC scenarios We assess pipeline storage capacity based on varying diameters and pressure limitations To estimate revenues from electricity sales in Chicago, we apply adjusted hourly marginal price data from the Commonwealth Edison system for the year 1999.
We developed a heuristic model to optimize electricity sales by maximizing revenues based on pipeline pressure, current and day-ahead electricity prices, and a fixed generating capacity of 2,300 MW in Chicago Our analysis assumes that electricity is sold in wholesale markets within the city The pipeline's storage capacity enables the storage of a portion of total kilowatt-hours (kWh) from their generation time to be sold during higher-priced hours In contrast, the HVDC scenarios operate without energy storage, selling all generated electricity instantaneously at the prevailing hourly price.
This article evaluates the expenses associated with delivering hydrogen gas to Chicago through pipelines, considering its use as fuel for surface vehicles, aircraft, and distributed generation (DG) By deducting the costs of electricity generation infrastructure in Chicago, we can determine the delivered cost of hydrogen across various scenarios.
14 Because electricity markets in Chicago are not yet fully deregulated, we adjust this price data to simulate competitive market prices These adjustments are described in Chapter 3.
The 2,300-MW generating capacity limit for hydrogen-based electricity production in Chicago was determined through iterative model runs aimed at maximizing revenue This capacity appears adequate to support a 4,000 MW wind farm operating at an average capacity factor of 40%, especially when considering storage capabilities However, the optimization of fuel cell or combustion turbine capacity in Chicago, factoring in associated costs, has not been addressed.
We anticipate that a wholesale energy company will develop the large-scale energy generation and delivery system, rather than a retail user aiming to offset retail electricity costs To evaluate the expenses associated with transporting wind power from the Dakotas to distributed generators in Chicago, we refer to our cost estimates for hydrogen-only delivery This allows us to compare these costs with the expenses of generating hydrogen in Chicago through steam methane reforming (SMR) of natural gas, ultimately determining the breakeven price for natural gas.
Annual revenues for each scenario are determined by aggregating hourly revenues throughout the year By subtracting total annual costs from total revenues, we can assess the annual profit or loss for each scenario.
Our analysis of wind energy storage in large hydro systems focused on gathering insights from personnel at two major Midwestern hydro facilities: the Western Area Power Administration (WAPA) in the United States and Manitoba Hydro (MH) in Canada.
We were prevented by time and budget constraints from modeling hydro storage scenarios.
Pipeline vs Electric Lines – Cost Model
Wind Generation Costs
In central North Dakota, we project a wind generating capacity of 4,000 MW across roughly 400 square miles With an average capacity factor of 40 percent, this setup is expected to yield an annual energy generation of approximately [insert annual generation figure].
14 million MWh (14 TWh) in an average year.
The estimated capital cost for wind generators is $950 per kW, with operating and maintenance (O&M) expenses at $0.008 per kWh, resulting in total annual costs of $567 million for wind generation This cost is not anticipated to see significant reductions between 2001 and 2010 However, for scenarios where wind costs decrease substantially, total system costs are recalculated based on a lower installed capital cost of $700 per kW.
Pipeline Costs
The cost of hydrogen pipelines remains uncertain, as no existing infrastructure matches the scale and purpose anticipated for future projects Current hydrogen pipelines operated by industrial gas and oil companies, while safe and profitable, are not designed for large-scale, long-distance renewable energy transmission or storage Cost estimates have been derived from outdated literature, primarily from the 1970s and 1980s, along with expert consultations in the gas pipeline and hydrogen research sectors Detailed costs, along with performance and revenue modeling, are discussed in Chapter 3.
17 See reference 6: Malcolm and Hansen, Results from the WindPACT Rotor Design Study, presented at Windpower 2001, Washington, DC, June, 2001.
18 Personal communication with D.J Malcolm, November 2001.
The Alliance Pipeline, which began service on December 1, 2000, is a key source of benchmark cost data for natural gas transportation Spanning 3,200 kilometers from northeast British Columbia to Chicago, this 36-inch pipeline operates at a pressure of 1,740 psi and has a capacity of 1.5 billion cubic feet per day The total capital cost for the pipeline, including gas gathering laterals, compressors, valves, meters, and terminals, was $3.3 billion Based on our analysis, we estimate that 1,600 kilometers (1,000 miles) of this pipeline would have cost approximately $1.5 billion To account for the anticipated increased costs of a hydrogen-service pipeline of the same diameter, we applied a 1.4 multiplier, a crucial assumption that warrants further investigation (refer to section 8, Recommended Future Work).
Costs for each of the six pipeline scenarios, for delivering wholesale electricity in
Table 2 presents various scenarios for hydrogen transport in Chicago, featuring a 36-inch pipeline in the first two scenarios and an 18-inch pipeline in the third Each scenario name comprises three key elements: the pipeline diameter (either "36" or "18"), the inclusion of an external compression system (designated as "C" for compression or "NC" for non-compression), and the hydrogen-to-electricity generation technology used, which can be either a fuel cell ("FC") or a combined-cycle gas turbine ("CT") Brief descriptions of these scenarios are also provided in Table 2.
In the “NC” scenarios, $200 million is deleted from the all-inclusive cost of the pipeline, to back out the capital cost of compressors.
HVDC Costs
The second option for transmitting wind energy from the Dakotas to Chicago involves the use of new High Voltage Direct Current (HVDC) power lines Current public-domain studies, vendor literature, and insights from engineers and researchers highlight the costs, benefits, and performance of HVDC technology HVDC lines are significantly more effective for long-distance, high-capacity electricity transmission, particularly for loads of 1,000 MW and greater, compared to traditional High Voltage Alternating Current (HVAC) power lines.
Energy losses over long distance are lower with DC lines;
DC lines are inherently controllable and stable; they have no reactive power;
Energy directional flow can be controlled, avoiding “power loops” on the grid;
The converter stations can supply reactive power support to the HVAC grid; and
Transmission line towers are smaller and less-obtrusive; less costly; require smaller ROW
Table 2 Assumed Costs of Hydrogen Pipeline Scenarios ($ million)
Scenario Capital Cost Annual Cap Cost Annual O&M Cost Total Annual Cost
36-C-FC (36" pipeline; low-pressure electrolysis with compression; 70% efficient SOFC fuel cells)
Compressors (in pipeline) (in pipeline) $37 $37
36-C-CT (36" pipeline; low-pressure electrolysis with compression; 60% efficient CC gas turbine)
Compressors (in pipeline) (in pipeline) $37 $37
36-NC-FC (36" Pipeline; high-pressure electrolysis; 70% efficient SOFC fuel cells)
36-NC-CT (36" Pipeline; high-pressure electrolysis; 60% efficient CC gas turbine)
18-NC-FC (18" Pipeline; high-pressure electrolysis; 70% efficient SOFC fuel cells)
18-NC-CT (18" Pipeline; high-pressure electrolysis; 60% efficient CC gas turbine)
HVDC systems necessitate expensive converter terminals at both ends of the line; however, the associated DC lines are more economical than HVAC lines and experience significantly lower losses Consequently, when considering the total costs, which include long-term capital and operational maintenance expenses, the overall costs of HVDC and HVAC systems can be comparable.
The "break-even distance" for high voltage direct current (HVDC) transmission typically ranges from 400 to 600 miles HVDC technology allows for efficient long-distance transmission through underground or undersea cables, maintaining loss levels comparable to those of overhead lines In contrast, underground or undersea high voltage alternating current (HVAC) transmission experiences significant losses when exceeding approximately 400 miles.
10 to 30 miles The contemplated transmission of 4,000 MW over 1,000 miles clearly favors the economics of HVDC over HVAC, with the added advantages of the other issues listed above.
Evaluating the costs associated with HVDC (High Voltage Direct Current) lines presents significant challenges due to the limited number of existing HVDC systems and the fast-paced advancements in technology and economics in this field.
We have costed and modeled three HVDC scenarios, named “HVDC-A” through
The analysis of "HVDC-C," detailed in Table 3, focuses on cost considerations, while performance and revenue modeling are discussed in Chapter 3 Each of the four scenarios is based on the configuration of two HVDC circuits and four power converter stations, with one station located at each end of the respective circuits.
In scenario HVDC-A the two circuits are mounted on separate sets of towers; in HVDC-
B, the two circuits are installed on one set of towers Less land is required for the ROW in HVDC-B, thus capital costs are lower Maintenance costs are also lower for HVDC-B. Converter station costs are the same for both HVDC-A and HVDC-B
In the HVDC-C scenario, the last 100 miles of the transmission system are installed underground due to the challenges of siting lines in suburban Chicago The permitting process for new overhead electric lines is becoming increasingly difficult, expensive, and time-consuming in congested urban areas, where right-of-way costs are notably high While underground installation may not completely eliminate public opposition, it remains a viable option for constructing HVDC lines In this scenario, both circuits are placed on a single set of towers, with the final 100 miles underground This underground segment raises construction costs, which are included in the capital costs, but it also lowers maintenance costs compared to non-underground options Annual capital costs for each HVDC scenario are calculated using a 13-percent annual capital recovery factor, as detailed in Table 3.
Underground cables necessitate a right-of-way (ROW) width of only 20 to 50 feet, compared to 150 to 200 feet for overhead lines While the operation and maintenance (O&M) costs for underground cables are lower due to their resilience against weather and hazards, the initial installation costs are significantly higher, ranging from four to eight times that of overhead lines However, advancements in cable manufacturing processes, such as extruded solid polymer dielectric, are expected to narrow this cost gap in the future.
The current capacity limit for HVDC underground cable systems is approximately 1,000 MW per circuit at +/- 500 kV To achieve this capacity, four complete HVDC cable pairs are necessary, resulting in a total of eight cables installed within a single trench Each cable measures around six inches in diameter and weighs about 20 pounds per foot.
Table 3 Assumed Costs of HVDC Scenarios ($ million)
Capital Cost Annual Cap Cost Annual O&M Cost Total Annual Cost
HVDC-A (two sets of towers)
HVDC-B (one set of towers)
HVDC-C (one set of towers; underground final 100 miles)
Pipeline vs Electric Lines – Profit Model
Wind and Market Price Data
The wind data utilized in our model originates from the actual output of a 100 MW wind plant in Chandler, Minnesota To adapt this data for a larger 4,000 MW wind project in North Dakota, we implemented two key adjustments Firstly, we smoothed the fluctuations in plant output to reflect the reduced variability expected over the expansive land area of the Dakota project This approach is grounded in the understanding that wind activity can significantly differ across a 400 square mile region, leading to more stable overall wind production as weather systems pass through the facility.
The rolling average of turbine output at the facility varies, with larger facilities experiencing a more consistent energy distribution over time This distribution helps to mitigate fluctuations in plant output, resulting in a smoother energy generation process.
Figure 2 Rolling Average Smoothing of Wind Data
To adapt the Chandler, MN data for a large wind facility, we utilized a five-hour rolling average on the hourly capacity factor of the wind plant Consequently, each hourly capacity factor for the hypothetical Dakota project is derived from the average of five data points from Chandler This adjustment's impact on the Chandler data for a typical day is depicted in Figure 2.
In our recent adjustments, we raised the annual average capacity factor of the wind plant from the current 36.2 percent at Chandler, MN, to the anticipated 40 percent for the more robust North Dakota wind resource for the year 2010 To achieve this increase in capacity factor, we applied a multiplier of 1.105 to each hourly capacity factor.
To establish hourly wholesale prices for the Chicago area, we utilized the 1999 hourly marginal costs from the Commonwealth Edison system, as market-based wholesale electricity prices were not available at that time Anticipating the emergence of a market with published prices in the coming years, we adjusted these hourly marginal costs to align with projections for competitive electricity market prices in the Chicago area for 2010.
24 For an analysis of these dynamics, see: R Hudson, B Kirby and Y Wan, The Impact of Wind
Generation on System Regulation Requirements, Oak Ridge National Laboratory, Oak Ridge, TN
25 See reference 51: G Czisch and B Ernst, ISET, in Proceedings of Windpower 2001, American Wind Energy Association (AWEA), Washington, DC, June 4-7, 2001
26 Lessons Learned in the DOE-EPRI Wind Turbine Verification Program (TVP), EPRI, McGowin et al,
Increased the volatility of the Commonwealth Edison marginal costs to be consistent with volatility seen in competitive markets in New England and the Pennsylvania/New Jersey/Maryland (PJM) area 27
The hourly prices have been doubled, resulting in an annual average price that aligns with the energy costs of a new CCCT power plant, estimated between $38 and $42 per MWh This price range is also supported by long-term forecasts from the Department of Energy, which suggest that future prices will mirror the costs of new capacity Furthermore, this average is in line with recent prices observed in competitive U.S electricity markets While a comprehensive statistical analysis of hourly price data was not included in this project, it is recommended as a crucial next step for further research.
We have adjusted the hourly wind and price data to enhance the simulation of the systems we aim to model, ensuring that actual data from operating systems is accurately represented Despite these adjustments, we maintain that the inherent variability of wind is still effectively captured, and the daily and seasonal price patterns are mirrored in the wholesale price data Crucially, the same adjusted wind and price data is consistently applied across all modeling scenarios, ensuring that our scenario comparisons remain unaffected.
Pipeline Revenues
The six pipeline scenarios are developed by modifying various elements of the pipeline system, such as the pipeline itself, electrolyzers, and the generating capacity in Chicago In the "36-C" scenarios, a low-pressure electrolyzer is paired with a separate compressor to elevate hydrogen to 1,000 psi at the pipeline's input, incurring additional capital and operational costs for the compressor Conversely, the "36-NC" and "18-NC" scenarios feature electrolyzers that operate at an output of 1,000 psi, eliminating the need for external compression The fuel cells in the "FC" scenarios utilize hybrid solid oxide (SOFC) units, complemented by a combustion turbine that harnesses byproduct heat, achieving an overall electrical efficiency of 70 percent Meanwhile, the "CT" scenarios incorporate large combined-cycle gas turbines with heat recovery steam generators, which operate at a total efficiency of 60 percent Detailed operating parameters for each of the three pipeline scenarios are presented in Table 4.
We analyze pipeline energy storage by permitting pressure variations between 500 and 1,000 psi, resulting in approximately 122 GWh of energy storage for a 36-inch pipeline and over 30 GWh for an 18-inch pipeline Additionally, we created a straightforward function aimed at maximizing electricity sales revenues in Chicago.
Two of the three fully deregulated power pools in the U.S are currently operational, with ISO California being the third However, it is anticipated that prices in this region will experience greater volatility compared to expectations for 2010.
28 See: U.S DOE, Annual Energy Outlook 2001, DOE/EIA-0383(2001), p 75 Document available at www.eia.doe.gov/oiaf/aeo.
(a) pipeline pressure, (b) current and day-ahead prices and (c) a Chicago generating capacity limit of 2,300 MW 29
Utilizing day-ahead price information aligns with the data accessible to traders in competitive power markets, enabling the sales function to maximize electricity sales during higher-priced periods while adhering to pipeline and generating capacity constraints Annual revenues are calculated by summing hourly revenues throughout the year In the "18-NC " scenarios, we assume a 90 percent electrolyzer efficiency to present an optimistic outlook for hydrogen transmission However, the 18-inch pipeline may be inadequately sized to consistently transmit 4,000 MW, potentially necessitating wind generation shedding, an economic optimization strategy not addressed in this report.
Table 4 Operating Parameters of Pipeline Scenarios
In our modeling, we incorporate total revenue figures from all pipeline scenarios, including the value of the oxygen (O2) byproduct generated during the electrolytic conversion of wind energy to hydrogen Coal gasification plants, particularly those utilizing the zero-emissions steam technology (ZEST) design, can leverage this oxygen along with water feedstock to produce hydrogen in synergy with wind energy Based on discussions with industry experts, we estimate the value of this process.
$19.17 per ton O2 delivered to the coal plant gate 31 The windplant electrolyzers will produce about 3.1 million tons of byproduct O2 in a typical year, worth $60.1 million at the coal plant
The generating capacity limit of 2,300 MW for hydrogen-based electricity in Chicago is determined through model runs aimed at maximizing revenue, distinct from wind capacity in North Dakota This limit appears suitable to support a 4,000 MW wind farm operating at a 40 percent average capacity factor, complemented by storage capabilities However, the optimization of fuel cell and combustion turbine capacity in Chicago, considering associated costs, has not been addressed.
30 Alliance Pipeline information package: system maps with receipt and delivery points; System Update, May and Fall, 1997, Winter/Spring and Summer, 1998, Spring, 1999, 1 st , 2 nd , 3 rd and 4 th Quarter, 2000, Calgary.
31 Estimated: Table ES-2, Parsons Corporation (recent) report, courtesy of Gary J Stiegel, Product Manager, Gasification Technologies, National Energy Technology Laboratory, Pittsburgh, PA 15236, gary.stiegel@netl.doe.gov
HVDC Revenues
The three HVDC scenarios are much more similar to each other than the six pipeline scenarios, for delivering wholesale electricity in Chicago The performance of the
HVDC systems operate similarly, with the primary distinction being their cost Each line requires two converter stations, which together incur energy losses of 1.5 percent Additionally, the lines themselves experience a loss of 0.4 percent for every 100 kilometers, leading to a total line loss of 6.4 percent Consequently, the overall efficiency of the system is around 92 percent.
The HVDC system facilitates the transmission of energy generated at the North Dakota wind plant to Chicago, where it is sold at the prevailing market-clearing price Unlike traditional pipelines, the HVDC system does not have the capacity to store energy, necessitating the sale of each kilowatt-hour produced Annual revenues are determined by summing the hourly earnings throughout the year.
Results
Delivering Electricity to Chicago
The cost of delivering electricity to Chicago varies significantly across nine scenarios, with pipeline options proving to be particularly expensive, ranging from 14 to 18 cents per kWh, which far exceeds the year 2000 average retail rate of 8.8 cents per kWh In contrast, HVDC scenarios offer a more economical alternative at approximately six cents per kWh; however, this price still remains higher than the wholesale market rates prevalent in the Chicago area for most hours throughout the year.
In this analysis, we emphasize the energy conversion losses associated with each scenario, presenting them as costs in our bar graph This approach allows us to accurately reflect the true expenses of other components, including wind generation and transmission Specifically, the modeled wind generation incurs an average cost of 4.32 cents per kWh when expenses are distributed across all generated kWh, rather than just those delivered to Chicago.
Figure 3 Cost of Delivered Electricity in Pipeline and HVDC Scenarios
The annual revenues for HVDC and pipeline scenarios reveal that all three HVDC scenarios generate identical revenues due to consistent wind generation, conversion losses, and energy sales, with variations stemming solely from costs Notably, HVDC scenarios yield the highest revenues compared to other scenarios, primarily because pipeline scenarios experience significantly higher energy losses during the conversion of electricity to hydrogen and back The overall efficiency in HVDC scenarios stands at 92 percent, while pipeline efficiency ranges from 51 to 63 percent.
32 Wholesale electricity prices include only the cost of power generation Retail prices also include the cost of transmission and distribution and other utility costs
36-C-FC 36-C-CT 36-NC-FC 36-NC-CT 18-NC-FC 18-NC-CT HVDC-A HVDC-B HVDC-C
Wind Gen Cost Transmission Cost Conversion Losses Chicago Gen Costs
HVDC 36-C-FC 36-C-CT 36-NC-FC 36-NC-CT 18-NC-FC 18-NC-CT
Electricity Oxygen PTC pipeline scenarios Figure 4 illustrates the portion of revenues coming from electricity sales, oxygen sales and the PTC 33
Figure 4 Annual Revenues for All Scenarios, including PTC
Revenue per megawatt-hour (MWh) of electricity sold is consistently higher in all pipeline scenarios compared to HVDC scenarios This is attributed to the pipeline's storage capacity, which enables a greater percentage of electricity sales during peak pricing periods For a detailed comparison of revenue per MWh across different scenarios, please refer to Figure 5.
To assess the value of pipeline storage capacity across various scenarios, we analyze the revenue differences per MWh between each pipeline scenario and HVDC scenarios without storage We then multiply this revenue difference by the total MWhs sold for each pipeline scenario, effectively calculating the average premium per MWh attributable to storage The findings indicate that the value of pipeline storage varies, with estimates reaching up to $191 million in the 18-NC scenario, as illustrated in Figure 6.
FC to $249 million in both 36-C-CT and 36-NC-CT.
Despite the energy storage benefits and higher revenue per MWh offered by pipelines, their high capital costs and significant energy losses render them unprofitable An analysis of costs versus projected revenues indicates that all pipeline projects result in annual losses, as illustrated in Figure 7 In contrast, HVDC scenarios, which feature lower project costs and reduced energy losses, approach a break-even point, yet they too would incur annual losses.
The Production Tax Credit (PTC) offers 1.7 cents per kilowatt-hour (kWh) for energy generated by wind plants Given that wind generation is consistently estimated at 14,017,289 megawatt-hours (MWh) across all scenarios, the revenue from the PTC remains constant at $283 million for each scenario.
Figure 5 Revenue per MWh, including PTC
HVDC 36-C-FC 36-C-CT 36-NC-FC 36-NC-CT 18-NC-FC 18-NC-CT
Figure 6 The Value of Pipeline Storage Capacity, including PTC
36-C-FC 36-C-CT 36-NC-FC 36-NC-CT 18-NC-FC 18-NC-CT
Figure 7 Annual Losses for Each Project Scenario, including PTC
To understand the costs of various energy scenarios, it's essential to compare them with the expenses associated with competing power generation technologies In the U.S., most new power plants being built are Combined Cycle Combustion Turbines (CCCTs), which often set wholesale prices during numerous hours in many power control areas Therefore, using CCCTs as a benchmark offers valuable insights for this comparison.
The Department of Energy's Annual Energy Outlook for 2001 estimates that the cost of energy from a new Combined Cycle Combustion Turbine (CCCT) in 2005 will be 4.16 cents per kWh, based on natural gas prices of $4.25 per mmBtu This figure is significantly lower than the projected total electricity costs, which range from 5.92 to 18.51 cents per kWh in various scenarios However, potential increases in natural gas prices or stricter mandatory CO2 reduction regulations could lead to higher electricity costs from CCCTs, while not impacting the costs associated with wind and hydrogen energy sources.
To determine the gas price increase necessary for our scenarios to remain competitive, we adjusted the natural gas component, which accounts for 2.79 cents per kWh or approximately 67% of the total cost for a new Combined Cycle Gas Turbine (CCCT) The findings, presented in Table 5, illustrate the gas prices at which electricity generated from each scenario would achieve cost parity with a new CCCT Additionally, Table 5 outlines the carbon emission costs, expressed in dollars per ton of CO2, required for each scenario to compete effectively with a new CCCT.
Table 5 Breakeven Natural Gas Prices and Carbon Taxes for Electricity from
CCCT, and for Each Scenario, including PTC
Breakeven Carbon Cost ($/ton CO 2 )
We verified that the wholesale prices in our pipeline model aligned with the total cost per megawatt-hour (MWh) of a new combined cycle combustion turbine (CCCT), based on the assumption that this type of plant would dictate prices in the long run.
Predicting natural gas prices is highly challenging, but it's clear that prices were significantly higher and more volatile during 2000 and 2001 compared to recent years In 2000, the annual average price reached $4.38 per mmBtu, while in 2001, it increased to $5.12 This surge can be attributed to the power supply issues in California, which led to a major utility's bankruptcy Notably, monthly average prices peaked at $8.23 and $9.47 per mmBtu in December 2000 and January 2001, respectively For context, prior to 2000, annual average natural gas prices had never exceeded $3.70 per mmBtu in the previous 25 years.
Analysts generally anticipate increased volatility in future gas prices, but opinions diverge on whether average prices will rise significantly A scenario where gas prices reach $5 to $7 per mmBtu by 2010 appears plausible, potentially making HVDC scenarios competitive However, the higher price range of $19 to $26 per mmBtu necessary for pipeline scenarios to be viable is considered unlikely.
The competitiveness of pipeline scenarios appears increasingly unlikely due to the carbon tax prices required Most discussions on carbon trading related to mandated CO2 reductions anticipate prices between $5 and $25 per ton of CO2 Historically, the majority of CO2 emission trades have seen prices remain below $5 per ton.
Delivering Hydrogen to Chicago
In light of the unprofitability of pipeline scenarios for wholesale electricity, we examine the costs associated with delivering hydrogen to the Chicago area, focusing on three hypothetical pipeline projects after excluding costs and energy losses from electricity generation The cost analysis for delivering wind energy as hydrogen is illustrated in Figure 8, where annual hydrogen production is calculated by subtracting electrolyzer losses from the total wind generation of 14,017,289 MWhs Additionally, the more optimistic "18-NC " scenarios are based on a more efficient electrolyzer, operating at 90 percent efficiency compared to 85 percent.
Wind energy costs have decreased to 2.62 cents per kWh, as illustrated in Figure 8, compared to 4.32 cents per kWh shown in section 4.1, which reflects the overall cost of electricity delivery to Chicago This reduction is attributed to the inclusion of estimated project revenues and the federal Production Tax Credit (PTC) as a revenue source in the calculations presented in section 4.1.
35 All prices cited here are for gas delivered to electric utilities See: Energy Information Administration,
Monthly Energy Review, January 2002, p 133 Available at www.eia.doe.gov.
Because we will not calculate estimated revenues from hydrogen sales here, we include the federal PTC as a 1.7 cent per kWh credit to wind costs here
Figure 8 The Cost of Delivering Hydrogen via the Pipeline Scenarios, with PTC
Projecting revenues from hydrogen sales is more challenging than forecasting electricity sales due to the current hydrogen market's concentration in oil and gas processing and nitrogen fertilizer production The price of merchant hydrogen, predominantly derived from natural gas, is closely linked to natural gas prices It is essential to evaluate how the cost of hydrogen from various scenarios in this paper compares to the competitive hydrogen costs that would arise with large-scale demand.
The most economical method for large-scale hydrogen production today is steam methane reformation (SMR) of natural gas, generating hydrogen at approximately 1.88 cents per kWh, based on a natural gas price of $4.00 per mmBtu The cost of natural gas accounts for 88 to 98 percent of the total expenses, with larger SMR facilities typically at the higher end of this range For the cost of SMR-produced hydrogen to match that of hydrogen from pipeline scenarios, natural gas prices would need to increase significantly A comparison of natural gas prices required to equalize SMR hydrogen costs with various scenarios is illustrated, indicating that these prices are comparable to those that would make electricity delivery scenarios competitive with a new combined cycle gas turbine (CCCT) power plant.
Figure 9 Natural Gas Costs to SMR Hydrogen Plants that Would Produce
Hydrogen Costs Equal to Those in the Pipeline Scenarios, with PTC
Assessing the Projects without the PTC
Sections 4.1 and 4.2 present data assuming that the federal PTC for wind generation remains in effect We now show results without revenue from the PTC Figure 10 shows annual losses for each project delivering electricity to Chicago with and without the PTC
Figure 10 Annual Losses from Projects, With and Without the Federal PTC
Table 6 builds on the analysis presented in Table 5, illustrating the natural gas prices and carbon costs necessary for electricity generated by a new combined cycle gas turbine (CCCT) in the Chicago area to match the costs of electricity from our scenarios that exclude the Production Tax Credit (PTC).
G as C os t ($ /m m B tu ) and carbon taxes shown here are not additive Either the natural gas price or the carbon cost would cause our scenario to be competitive.)
Table 6 Breakeven Natural Gas Prices and Carbon Taxes, Without the Federal PTC
Breakeven Carbon Cost ($/ton CO 2 )
Figure 11 shows the natural gas costs to an SMR hydrogen plant that would result in hydrogen costs equal to our pipeline scenarios Obviously, both the costs shown in Table
6 and Figure 11 are higher than those in section 4.2, where the effect of the PTC is included.
Figure 11 Natural Gas Costs to Steam Reforming Hydrogen Plants that Would
Produce Hydrogen Costs Equal to Those in the Pipeline Scenarios, Without the Federal PTC
Assessing the Projects With Lower Wind Generator Capital Costs
According to Tables 4 through 6, the installed cost of wind generators is projected at $950 per kW While this estimate is considered accurate for wind costs in 2010, many industry analysts anticipate substantial cost reductions throughout the decade.
The analysis of wind scenarios indicates that with an installed capital cost of $700 per kW for wind turbines, overall project costs are outlined in Appendix A While lower wind costs can reduce annual project losses, most projects remain unprofitable, with the exception of one that achieves profitability under these conditions Notably, the HVDC-B scenario, which features two HVDC systems on a single set of towers, generates annual revenues of $45 million.
Figure 12 Annual Losses With Wind Capital Costs at $700 per kW, with PTC
Table 7 illustrates the gas prices and carbon costs necessary for electricity generated by a new Combined Cycle Gas Turbine (CCCT) in the Chicago area to match the costs of electricity from our scenarios, specifically highlighting the role of wind energy.
The projected cost of electricity generation from HVDC scenarios, estimated at $700 per kW with PTC, is expected to be slightly lower than that of new combined cycle gas turbines (CCCT), as the necessary gas prices fall below anticipated future levels and carbon costs are negative However, the breakeven prices and carbon costs for pipeline scenarios remain improbable.
Table 7 Breakeven Natural Gas Prices and Carbon Taxes With Wind Capital
Costs at $700/kW, with PTC
18-NC- CT HVDC-A HVDC-B HVDC-C
Some readers might mistakenly believe that a new Combined Cycle Gas Turbine (CCCT) would not be profitable based on the hourly prices presented in Figure 12 and Table 7, especially since scenarios HVDC-A and HVDC-C appear unprofitable and generate electricity at a lower cost per kWh However, this conclusion overlooks the critical factors of wind generation variability and the dispatchability of a CCCT Although the cost per kWh for HVDC scenarios is marginally lower, the reliability and flexibility of a CCCT could ultimately enhance its profitability.
If the cost of electricity were $700 per kW, the revenues for the Combined Cycle Gas Turbine (CCCT) plant would significantly increase, as it would only function during peak pricing hours In contrast, wind and High Voltage Direct Current (HVDC) projects sell all generated electricity immediately at the prevailing market price, often resulting in losses during numerous hours throughout the year when total project costs per kilowatt-hour are taken into account.
While we did not specifically model the profit or loss of a new Combined Cycle Gas Turbine (CCCT), the data presented in Figure 12 and Table 7 suggests that such a facility would likely experience minimal profits or small losses.
As seen in Figure 13, SMR hydrogen production is projected to be far less costly than our pipeline scenarios, even assuming wind costs at $700 per kW.
Figure 13 Natural Gas Costs to SMR Hydrogen Plants that Would Produce
Hydrogen at Costs Equal to Those in the Pipeline Scenarios with Wind Capital Cost at $700 per kW, with PTC
The Cost of Electricity from Distributed Generation Using Hydrogen from
In section 4.1 above we present the costs of wholesale electricity delivered via the pipeline and HVDC scenarios We compare these costs to the cost of electricity from a
Gas Price without ROI Gas Price with ROI
To ensure competitiveness in electricity pricing, natural gas prices must increase to between $16 and $23 per mmBtu for the new CCCT power plant With the growing interest in distributed generation (DG), it's important to evaluate how our pipeline cost estimates impact retail electricity settings One of the key advantages of DG is its ability to bypass transmission and distribution costs included in retail rates, suggesting that our pipeline projects could be more economically viable when supplying fuel to DG units competing against retail electricity prices.
In comparing the cost of hydrogen delivered to Chicago with the estimated total operating costs of selected distributed generation (DG) technologies from 2010, it is crucial to note that the projects evaluated in sections 4.1 and 4.2 are large-scale energy supply initiatives Typically, developers of significant energy resources, such as oil fields or power plants, also construct the necessary transmission infrastructure to transport energy to wholesale markets.
In the future deregulated electricity industry, it is unlikely that a single energy company will manage large-scale resources, transmission infrastructure, and provide small-scale generating units or retail electricity to end users Regulators are separating the wholesale and retail sectors to prevent potential anti-competitive practices by companies involved in both energy generation and delivery Consequently, distributed generation (DG) units are expected to be owned by end users or energy service companies, while transmission and distribution (T&D) companies will own the power lines, and generating resources will be held by dedicated generating companies.
The operational costs of a distributed generation (DG) unit using hydrogen from pipeline scenarios are likely to be shared among three key parties: the windplant owner, the pipeline project owner, and the energy user or service company utilizing the DG unit The decision to install a DG unit and select its fuel source rests with the DG unit owner In this context, pipeline hydrogen will compete with natural gas and hydrogen from alternative sources, making it crucial to compare the costs of hydrogen against those of natural gas and other fuels This analysis aims to assess whether the total costs of operating DG on pipeline hydrogen are more competitive than the delivery of wholesale electricity or hydrogen, as discussed in previous sections.
Figure 14 illustrates the operational costs of three distributed generation (DG) technologies—internal combustion engines (ICE), microturbines, and fuel cells—using hydrogen across three pipeline scenarios, which align with the costs outlined in section 4.2 The cost assumptions for these technologies, detailed in Appendix B, are derived from the Distributed Resources Emissions Model created by the Natural Resources Defense Council (NRDC) We have modified this data to reflect anticipated cost reductions expected by 2010.
Distributed generation (DG) refers to small-scale generators, typically under one megawatt, situated near the electricity consumption point, effectively displacing retail-value electricity Recent advancements in technology, including microturbines and fuel cells, along with decreasing costs, have significantly increased interest in DG due to its reliability benefits.
Figure 14 The Cost of Electricity from DG Units Operating on Pipeline
Hydrogen from North Dakota Wind Energy
The total cost of operating distributed generation (DG) on hydrogen from pipeline scenarios significantly exceeds the current retail rates in Illinois, which stood at an average of 8.8 cents per kWh for residential customers in the year 2000 Among the various scenarios, the most competitive option is a fuel cell utilizing hydrogen from the 18-inch pipeline It's important to note that the cost estimates for these pipeline/DG scenarios are optimistic, as they do not account for the expenses associated with hydrogen distribution infrastructure needed to transport the gas from the pipeline hub to the end-use location in Chicago.
To analyze the effects of pipeline hydrogen costs versus our assumptions for distributed generation (DG) technologies, we present the operational costs of these technologies using natural gas, as illustrated in Figure 15 The electricity generating cost data utilized aligns with that in Figure 14, based on a natural gas price of $4.50 per mmBtu It is important to note that our projected DG costs for 2010 are estimated to be 5 to 15 percent lower than the average residential rates in Illinois from the year 2000.
39 Retail price figure is taken from the U.S Energy Information Administration’s publication, Monthly
Retail Rates, available at: www.eia.doe.gov.
ICE Microturbine Fuel Cell Residential Avg.
Figure 15 The Cost of Electricity from DG Units Operating on Natural Gas at $4.50 per mmBtu
Nat Gas Fueled Residenatial Avg.
The Hydro Firming Opportunity
Key Issues
Three categories of issues come up when thinking about using a hydroelectric system to
“firm” intermittent energy resources such as wind These categories are:
The “capacity and energy” profile of the hydro system,
The economics of the transaction.
The initial three categories focus on inquiries regarding the hydro system's capability to deliver firming services and the extent of energy it can provide for this purpose The fourth category addresses the conditions under which the hydro system would be prepared to offer such services, contingent upon its ability to do so.
The hydro system's resource and load profile can be categorized into two types: capacity constrained and energy constrained A capacity constrained system lacks sufficient generating capacity to meet peak load demands, even if it can generate enough energy annually for its customers To address this, it must acquire additional resources or energy for peak periods Conversely, an energy constrained system has adequate capacity to handle peak loads but struggles with insufficient water flows to meet annual energy needs Such a system may need to purchase extra energy during off-peak times to complement its dam output.
A hydro system that is capacity constrained is not likely to be willing to enter into a firming agreement with an intermittent resource – at least not during its peak use seasons.
The windplant can supply energy that the hydro system has in abundance, while the hydro system requires additional capacity An energy-constrained hydro system is likely to seek a firming arrangement, which would enable it to generate revenue that can be used to acquire more energy or benefit from a ratio trading deal involving net kilowatt-hours (kWh).
Constraints on river operation play a crucial role in assessing a hydro system's ability to deliver firming service A significant consideration is the type of dams utilized by the hydro company Dams classified as "run-of-river" or "low-head" are designed to harness the river's energy at specific locations without retaining substantial water volumes behind them.
“Impoundment” or “high-head” dams do store large amounts of water, and thus energy
A system with significant impoundment capacity offers greater flexibility in power generation compared to one that relies mainly on run-of-river capacity This enhanced flexibility may lead to a greater readiness to participate in firming arrangements However, it's important to note that there are additional constraints affecting river operations.
Companies managing dams face operational constraints due to competing river uses, primarily in river navigation, flood control, and environmental protection These constraints limit the flexibility of power companies in regulating water flow through dams, often requiring them to release excess water when electricity demand is low or to withhold water when demand is high.
Persistent droughts can significantly impact the generating capacity of hydroelectric companies While average water levels in major rivers fluctuate slowly due to multi-year trends, this uncertainty may deter hydro companies from committing to long-term contracts of five to ten years However, the relative stability of water levels allows for effective planning in the near to medium term.
The availability of transmission capacity plays a crucial role in the feasibility of hydro firming transactions Although limited transmission capacity is not as detrimental as other factors, the expenses associated with acquiring additional capacity can significantly impact the financial viability of hydro firming agreements.
In the extreme case, the need to construct new power lines could cause a windplant to abandon a potential hydro firming arrangement
In evaluating the hydro system's capability to offer firming services, it's essential to consider the terms of the arrangement This involves the hydro system exchanging less valuable variable energy (kWhs) for more valuable firm energy (kWhs) The market value of the intermittent energy from the wind plant, compared to the hydro system's firm energy, can be estimated through the wholesale power markets available to both systems The difference between the average short-term spot market energy price and the price of firm energy highlights the market value of the firming service that the hydro system can provide.
Firming Possibilities in North Dakota
Wind plants in North Dakota have access to two significant hydroelectric systems nearby that could potentially offer firming services These are the Upper Great Plains system operated by the Western Area Power Administration (WAPA) along the Missouri River, and Manitoba Hydro’s resources in Manitoba Both systems boast considerable hydroelectric generating capacity exceeding 2,000 MW and feature extensive transmission networks for efficient power distribution.
Below, we describe our initial findings from discussions with WAPA and MH staff about their ability and interest in providing firming service
5.2.1 Western Area Power Administration (WAPA )
WAPA's primary energy resources in the Upper Great Plains (UGP) consist of eight large dams on the Missouri River located in Montana, North Dakota, and South Dakota, providing a total generating capacity of around 2,200 MW during periods of adequate precipitation With a coincident peak load of approximately 1,900 MW in this region, WAPA maintains a reserve margin of just under 14 percent, indicating that while it is not capacity constrained, the capacity margin is relatively small compared to the traditional planning standard of 15 percent among U.S utilities, which is currently declining.
WAPA operates as an energy surplus system in non-drought years, but faces energy constraints during drought periods To meet customer demands, WAPA purchases additional energy during drought years and occasionally in surplus years due to mismatched water releases and load patterns For instance, in the year 2000, WAPA purchased 2,834 GWhs to ensure reliable energy supply.
WAPA effectively meets peak customer demand without capacity or energy constraints; however, it encounters substantial operational limitations regarding its dams on the Missouri River The management of UGP dams by WAPA adheres to specific regulations and guidelines.
“Master Water Control Manual,” written by the Army Corp of Engineers This
The wholesale price of firm energy represents the hydro company's opportunity cost, reflecting the potential loss incurred by supplying firm energy to the wind plant By considering the value of the intermittent wind energy, the difference between the firm energy price and the intermittent energy value determines the additional amount needed to equalize the value of both transactions for the hydro company.
41 The dams are actually operated by the Army Corps of Engineers
The WAPA's 2000 Annual Report, available at www.wapa.gov/geninfo/pppsmb.htm, highlights the ongoing updates to the Master Manual, which outlines essential operating procedures These procedures aim to effectively manage river resources while balancing objectives such as navigation, flood control, environmental protection, irrigation, water quality, recreation, and power generation.
There is significant uncertainty regarding the upcoming revisions to the Master Manual, with potential legal challenges looming, as various groups have expressed their intent to sue if the changes fail to align with their objectives.
WAPA staff acknowledge their understanding of the wind firming concept; however, they believe it is premature to pursue this idea until the Master Manual revisions are completed They anticipate that these revisions may limit their flexibility in river operations compared to previous practices.
Transmission capacity is unlikely to hinder a firming arrangement between North Dakota wind energy and WAPA If 4,000 MW of wind capacity is developed in North Dakota, substantial transmission upgrades will be necessary for interconnection Considering a hydro firming arrangement during these transmission investments could allow for new infrastructure to be implemented in a way that reduces additional transmission needs However, a thorough transmission study is essential to identify the complete transmission requirements for this arrangement.
Manitoba Hydro (MH) is a Crown Corporation owned by the Province of Manitoba, boasting approximately 4,800 MW of hydroelectric capacity across 12 dams With nearly 80 percent of this capacity located in the northern region of the province, far from southern load centers like Winnipeg, MH has constructed two 900-km High Voltage Direct Current (HVDC) lines connecting the northern facilities to the Dorsey Substation, situated just 26 km from Winnipeg This infrastructure includes three converter stations to facilitate efficient energy transmission.
The implementation of HVDC lines has allowed Manitoba Hydro (MH) to operate without capacity or energy constraints In fiscal year 2001, MH generated more than 32,500 GWh while only selling 20,100 GWh to end users in Manitoba, resulting in an impressive energy surplus of 38 percent Additionally, the company's capacity margin exceeded 30 percent, highlighting its significant operational flexibility.
MH actively participates in wholesale power markets, having exported over 12,000 GWhs—38 percent of its total generation—in FY 2001, primarily to the U.S., particularly the Minneapolis region Unlike WAPA, MH views wholesale power markets as a significant revenue source, frequently purchasing electricity during off-peak hours to optimize water conservation for peak generation.
Despite facing similar competing river uses as WAPA, MH benefits from significantly greater water access, providing it with enhanced operational flexibility However, 86% of MH's hydro capacity relies on run-of-river systems, which limits its control over output compared to companies with larger impoundment dams, although it still retains some ability to manage these facilities due to the river sizes involved.
To effectively harness and firm significant amounts of wind energy from North Dakota, Manitoba Hydro (MH) must substantially enhance its transmission capacity Currently, there are only three HVAC interconnections linking Manitoba to the United States: a 230-kV line from Winnipeg to Grand Forks, ND, another 230-kV line from Winnipeg to Duluth, MN, and a 500-kV line from Winnipeg to Minneapolis, MN.
The lines are frequently congested, particularly during peak times when they facilitate MH's exports to the U.S Considering MH's focus on the U.S wholesale power markets, it is reasonable to anticipate the company’s willingness to collaborate with other stakeholders in sharing the costs of new interties.
Additional Analysis
While hydro systems are hesitant to estimate their potential energy firming capabilities, we can analyze the maximum demand placed on them by a firming agreement This situation arises when wind energy output is at its lowest, particularly during the hours when the hydro partner is expected to deliver firm energy In such scenarios, if wind output drops to zero, the hydro system must generate the total amount of agreed-upon firm kilowatt-hours (kWh) in addition to fulfilling its other commitments Consequently, during certain times of the year, the hydro system is required to produce the full energy amount stipulated in the firming agreement, particularly during peak demand hours.
In 2000, WAPA had a mere 300 MW of capacity beyond its peak load, highlighting the limitations on additional firm capacity each system can commit to U.S electricity control areas mandate that market participants cannot take on firm commitments equal to their peak load; they must secure capacity that exceeds their firm load to support the regional capacity reserve margin Under the regulations of the Mid-Continent Area Power Pool (MAPP), WAPA may currently possess minimal capability to firm intermittent energy.
According to WAPA, the ability to firm wind energy is significantly constrained during drought years, such as the current one This winter, three out of six dams are at full capacity, leaving little room for operational flexibility.
MH clearly has more room to firm wind energy than WAPA The company had 1,574
In FY 2001, the company had excess capacity of over 1,000 MW to serve its Manitoba customers, after accounting for 500 MW of firm commitments outside the province With a 10 percent reserve margin, this allowed for a commitment of approximately 500 MW of firm energy However, establishing the necessary transmission for this firm energy arrangement could be challenging and potentially expensive due to the need for new lines, a concern echoed by Manitoba Hydro staff.
Significant enhancements to existing electric transmission systems in the Great Plains of the USA and Canada could impact hydro-firming strategies in the near future, as the vast wind resources available in the region far exceed the capacity for effective hydro-firming.
Summary of Findings
The analysis reveals that none of the examined cases, including the current federal Production Tax Credit (PTC), are financially viable for supplying electricity to the Chicago wholesale market or for providing hydrogen gas for distributed generation and fuel for vehicles and aircraft.
The cost of delivering wind energy from North Dakota to Chicago, including transmission expenses, ranges from 6 to 18 cents per kWh, making it uncompetitive For electricity generated from pipeline scenarios to be viable against a new combined-cycle combustion turbine, natural gas prices must increase to between $16 and $23 per mmBtu Conversely, if gas prices are between $4.30 and $5.30, high-voltage direct current (HVDC) scenarios would become competitive with a new combined-cycle combustion turbine.
The cost of delivering hydrogen via the pipeline scenarios ranges from 5.8 to 8.1 cents per kWh Natural gas prices would have to rise to a range of $11.50 to
$19.00 to make this hydrogen competitive with hydrogen produced from steam methane reforming (SMR) of natural gas.
The federal Production Tax Credit (PTC) for wind energy plays a crucial role in the financial viability of projects, as its removal can lead to project losses of 20 to 30 percent for pipeline initiatives and over 100 percent for certain high-voltage direct current (HVDC) projects.
Assuming total installed wind costs in 2010 are $700 per kW instead of $950 per kW leads to a reduction in projected annual losses, making the HVDC-B scenario profitable However, the pipeline scenarios still do not achieve profitability, even with the lowered wind costs.
The oxygen produced during hydrogen generation through electrolysis can be a valuable resource when transported short distances, particularly to meet the needs of new "clean coal" plants in North Dakota.
Much further study is needed to validate these study results Further work is especially needed in the areas of hydrogen pipeline costs and HVDC costs.
Hydrogen pipeline transmission for renewable energy sources faces several obstacles:
1 High capital costs for electrolyzers (and compressors, if 1,000 psi electrolyzers are not available), and for the electricity generating systems at destination;
2 Energy conversion losses in electrolyzers;
3 Low capacity factor of the pipeline;
4 Economic competition from HVDC electrical transmission and point-of- use hydrogen storage;
5 Hydrogen embrittlement in high pressure, variable-pressure, steel hydrogen transmission pipelines providing cushioning and storage;
6 Optimizing collection and conversion topology at sources; and
7 Acceptance by the public, and by the insurance and finance industries.
Other Considerations
Energy Security
The wind resource of the Great Plains has the potential to meet a substantial portion of the United States' energy needs, effectively displacing a considerable amount of imported oil and natural gas while significantly lowering CO2 emissions.
The efficient collection, concentration, and transmission of renewable energy sources, such as wind, will require the development of extensive electric transmission lines or hydrogen pipelines However, as highlighted by Amory Lovins in "Brittle Power: Energy Strategy for National Security," these large-scale systems are susceptible to sabotage, raising concerns about their vulnerability.
Underground systems, such as the hydrogen pipeline or the superconducting “energy pipeline” 44 in 8.2.5, would probably be less vulnerable than overhead HVDC lines.
Biomass Synergy
Harnessing energy from biomass, whether as electricity or hydrogen, can significantly enhance the transmission system's capacity factor by strategically generating power at various points along the route The seasonal variability of both wind and biomass energy suggests a complementary relationship, allowing for efficient energy management By stockpiling certain biomass resources, generation plants can be activated to support wind energy contributions to the transmission system With a 1,000-mile transmission network, biomass resources could potentially match the output of 4,000 miles, optimizing energy distribution and reliability.
MW peak wind capacity modeled here.
Energy delivery nodes in HVDC systems can be expensive at lower capacities, with vendors recommending a minimum size of 500 MW to achieve cost efficiency per kilowatt for converter stations In contrast, energy delivery nodes along large hydrogen gas transmission pipelines can be more straightforward and cost-effective, even at lower capacities, typically requiring just a boss on the pipe, a valve, a meter, potentially a compressor, and a small building.
Coal Synergy
New "clean coal" plants in North Dakota, such as the ZECA plant for electricity and the ZEST plant for hydrogen, have the potential to enhance energy production by utilizing byproduct oxygen in hydrogen transmission scenarios These coal plants could work in tandem with wind energy facilities, improving the transmission capacity factor and reducing the cost per kWh for wind energy delivered to Chicago Given the challenges in adjusting coal plant output, hydrogen transmission may offer greater advantages due to its ability to be compressed and stored efficiently in pipelines or other storage media.
Carbon Taxes and Internalizing Other Externalities
To address the significant market price disparity between Great Plains wind energy and fossil fuel sources, implementing substantial national and international taxes on CO2 emissions from fossil fuel combustion is essential These taxes would not only discourage anthropogenic emissions but also help internalize the external costs associated with fossil fuels.
International Collaboration
Several collaborative opportunities, especially with Japan, Germany, and Canada, for hydrogen transmission technical and economic study, should be pursued 45
Define “Renewables-Hydrogen Economy”
The hydrogen community and renewable energy advocates must work together to establish and assess the prospects of a "renewables-hydrogen economy." This collaboration is crucial for effectively collecting and transmitting diverse renewable resources from remote locations to distant markets A key consideration is whether energy, such as wind power from the Great Plains, should be transmitted as electricity or converted into hydrogen for markets like Chicago.