Our natural gas research looks for opportunities in the energy transition. Specifically, natural gas is the lowest-carbon fossil fuel. Methane has a chemical formula of CH4. Thus 1mcf of methane contains 304kWh of energy, of which 46% is from combusting carbon atoms into CO2 and the other 54% is from combusting hydrogen atoms into innocuous H2O.
By contrast, fuels such as coal are effectively pure carbon, substantively all of their energy is derived from combusting carbon into CO2. Thus they are 2x more CO2 intensive per unit of energy. This is why our roadmap to net zero effectively eliminates unabated coal usage, which in turn requires ramping natural gas by 2.5x, to around 275 TCF pa in 2050.
This fuel-switching delivers almost as much decarbonization in our models as renewables themselves. Gas power is an effective back-up for times when the sun is not shining and the wind is not blowing.
This is not a free pass for the gas industry. It is also important to produce and consume gas as cleanly and efficiently as possible. This includes mitigating methane leaks, increasing the efficiency of turbine technologies (especially combined heat and power) and capturing remaining CO2, such as via CCS or blue hydrogen.
Overall our natural gas research in the energy transition does find good, pragmatic and low cost opportunities ahead for the natural gas industry.
This data-file tabulates the five ‘Big Oil’ Super-Majors’ development capex from the mid-1990s, in headline terms (billions of dollars) and in per-barrel terms ($/boe of production). Real development capex quadrupled from $6/boe in 1995-2000 to $24/boe in 2010-15, and has since collapsed to $10/boe.
The peer group of Super-Majors comprises ExxonMobil, Chevron, BP, Shell and TOTAL, which comprise c10% of the world’s oil production and 12% of the world’s gas production. As a good rule of thumb, this group can be thought of as c10% of global production.
Development capex by region: gaining share? The US has always been the most favored destination, attracting c25% of all development capex, both offshore (e.g., Gulf of Mexico) and increasingly for short-cycle shale. However, the share of these companies’ development capex in the US has averaged around 32% in the past three years.
Development capex by region: losing share? Development projects in Africa and Europe have fallen most out of favor. Development capex in Africa peaked at $17bn in 2009, almost 25% of the group’s total development capex, and has since fallen back to $5bn per year, or 8% of the group’s total development capex.
It is somewhat terrifying to consider that the industry needed to spend an average of $15/boe (real terms) on development capex in order to hold its organic production “flattish” (including some large acquisitions in 2014-17, such as Shell buying BG).
Another scary data-point is that this peer group of Super-Majors spent $18/boe (real) on development projects in the decade from 2004-14 (which is 80% more than recent levels of spending) yet its net production declined by 1.5% per year over this timeframe.
Similar data for the Super-Majors’ exploration capex over time is tabulated here.
Under-investment across the entire energy industry may foreshadow a sustained shortage of energy, especially if 50% lower-carbon gas is intended to replace coal as part of the energy transition, per our roadmap to net zero. Hence one cannot help wondering about energy shortages, energy pragmatism and our fears of another up-cycle.
This data-file aggregates the Oil Majors’ development capex, across ExxonMobil, Chevron, BP, Shell and TOTAL disclosures, apples-to-apples, back to 1995, based on supplementary oil and gas disclosures, in the SEC’s EDGAR archives.
The flue gas of a typical combustion facility contains c7% CO2, 60ppm of NOx, 40ppm of SOx and 2ppm of particulate dusts. This is our conclusion from tabulating data across 75 large combustion facilities, mainly power generation facilities in Europe. However, the range is broad. As a rule of thumb, gas is cleanest, biomass and coal are worse, while some diesel-fired units are associated with the lowest air quality in our sample.
Sulphur oxides (SOx) cause acidification, in the air, in rain and in natural habitats. Hence limits are placed on the sulphur emissions in the exhaust gases of large power facilities. The limits are typically 50-250ppm in Europe, 120ppm in the US and 75-300ppm in China. We think European coal plants emit 20-400 ppm of SOx, with an average of 85ppm, which has been reduced by installing gas scrubber units in recent years. Emissions from natural gas plants are effectively nil.
Nitrogen Oxides (NOx) cause ground-level ozones and smogs to form, which can contribute to respiratory problems. Thus limits in the exhaust gases of large power plants are 60-130ppm in Europe, 90-120ppm in the US and 75-150ppm in China. We think the average coal plant in Europe emits NOx at 110pm. The numbers are highest for large diesel plants averaging 160ppm, high for biomass plants averaging 80ppm, and lowest for gas turbines averaging 25ppm at CCGTs.
Particulates and dusts are combustion products that become airborne and are later deposited on buildings, machinery, natural habitats or worst of all inhaled. Dusts are limited to 3-9 ppm in the emissions of large power plants in Europe, 17ppm in the US and 22ppm in China. The average coal plant emits at 9 ppm in Europe, due to the installation of electrostatic precipitators and other exhaust gas treatments. Again, biomass and diesel plants can have high particulate emissions. Gas fired power plants seem to have particulate emissions well below 1ppm.
Underlying data on different power plants are broken down in this data-file. Note that European databases report estimated SOx, NOx and particulate emissions for large combustion facilities in tons, but we have applied our own back-of-the-envelope conversion factors, to translate the data into ppm and mg/m3 emissions intensities.
A typical simple-cycle gas turbine is sized at 200MW, and achieves 38% efficiency, as super-heated gases at 1,250ºC temperature and 100-bar pressure expand to drive a turbine. The exhaust gas is still at about 600ºC. In a combined cycle gas plant, this heat can be used to produce steam that drives an additional turbine adding 100MW of power and c20% of efficiency, for a total efficiency of 58%. This data-file tabulates the operating parameters of gas turbines.
Why do gas turbines matter? Recuperated Brayton cycles are going to be a defining technology of the energy transition and a complement to renewables. The thermodynamics are explained here. The key point is that gas-fired power cycles are totally different from steam cycles. They run off a fuel that is 50% lower carbon than coal. They can realistically be 2-3x more efficient per unit of fuel. They are more flexible (data here). And they may also be easier to decarbonize directly (example here).
How does a gas turbine work? First, air is drawn into a compressor. The compression ratio is typically around 20x. The pressurized air is then heated by combusting a fuel. The result is a very hot, very high-pressure gas. This can be used to drive a turbine as it expands. For example, expanding 1 ton of gas from a turbine inlet temperature of 1,250ºC and a turbine inlet pressure of 100-bar, down to an exhaust gas temperature of 600ºC and near-ambient pressures, might see volumes increase by around 25x (chart below).
Simple cycles versus combined cycles. If the 600ºC exhaust gas is simply discharged into the atmosphere, then a typical simple cycle gas turbine will achieve 38% efficiency, converting natural gas into electricity. But there is still a lot of energy in a 600ºC exhaust stream, which can be used to evaporate water, produce high pressure steam, and then drive an entirely separate turbine. This is a combined cycle configuration. And it adds another 20% efficiency, yielding a total efficiency of 58%.
Note that the steam cycle described above, powered by the waste heat from a gas turbine, is effectively the same as the primary heat cycle used in other conventional thermal power plants (Rankine cycle). This is remarkable.
The efficiency of a simple cycle gas turbine depends primarily on the turbine inlet temperature and pressure, which in turn depend on the compression ratio. The most efficient simple cycle gas turbines hit 43% efficiency, with compression ratios of 25-30x, turbine inlet pressures of 140-180 bar and turbine inlet temperatures of 1,400-1,600ºC. It is quite hard to get hotter than this, because things start to melt. But consider, for contrast, that a steam cycle really struggles to surpass 300-500ºC.
Why does a gas turbine look like that? To achieve these high compression ratios a typical gas turbine will have 12-22 separately optimized and sequential compression stages. And to maximize power output in the turbine, it will typically have 4 turbine stages. This explains the classic cross sectional profile of a gas turbine.
How fast does a gas turbine spin? A simple cycle gas turbine typically spins at 3,000-4,000 revolutions per minute (rpm). The compressor is connected to the same shaft as the turbine. The back-work ratio imparted to the compressor is equivalent to around 40-50% of the net work driven through the turbine.
How large is a gas turbine? A typical 200MW gas turbine might take up 60 m2 and weigh 300 tons. Good rules of thumb are 0.3 m2/MW of areal footprint, and 2 tons/MW of weight. Although larger gas turbines are more compact (on a per MW basis).
What is the cost of a gas turbine? A typical gas turbine might cost $200/kWe (chart below). Larger gas turbines have lower costs per MW (chart below). However note that our model of a gas-fired power plant assumes total capex of $850/kW. In other words, total installed capital costs are typically around 4x larger than the turbine itself.
(This multiple may be worth keeping in mind amidst debate about hydrogen electrolyser costs. Some companies have been guiding to $200-300/kWe electrolyser selling prices, and some analysts noting that this realistically means around $1,000-1,200/kW fully installed costs).
Emissions from natural gas power plants are generally low. CO2 intensity is 0.3 kg/kWh from a 60% efficient combined cycle gas turbine (up to 70% below coal power plants). NOx emissions are usually below 25ppm but can be as low as 2ppm in the best models. Many new turbines are also hydrogen ready, and have been qualified for 25-75% hydrogen blending.
Flexibility of a gas fired power plant is middling to high. A typical plant can ramp up or down by 15% of its nameplate capacity per minute, turn down to c25-50% of its load, and start up from cold in 20-minutes. Different examples are tabulated in the data-file.
Our outlook for gas turbines in the energy transition is published here. Leading companies in gas turbines are profiled here. Gas turbine operating parameters are compiled for a dozen gas turbine models in this data-file, as a useful reference, mainly designs from Siemens Energy, GE, Mitsubishi-Hitachi and Ansaldo.
NET Power has developed a breakthrough power generation technology, combusting natural gas and pure oxygen in an atmosphere of pure CO2. Thus the combustion products are a pure mix of CO2 and H2O. The CO2 can easily be sequestered, yielding CO2 intensity of 0.04-0.08 kg/kWh, 98-99% below the current US power grid. Costs are 6-8c/kWh. This NET Power technology review presents our conclusions from patents.
NET Power was founded in 2010, is headquartered in Durham NC, has >30 employees, and has developed an efficient, gas-fired power generation technology with “in-built CCS”.
Specifically, the reactor produces a pure stream of H2O and CO2, which can easily be dehydrated, then a portion of the CO2 can be siphoned off for disposal, while the remainder is re-circulated, as the working fluid in the thermodynamic cycle.
In 2022, Rice Acquisition Corp II agreed to combine with NET Power, at an EV of $1.5bn, with $235M of commitments from the Rice family, Occidental Petroleum and others.
NET Power aims to generate reliable electricity from natural gas and capture the emissions. CO2 intensity is stated at 0.04-0.08 kg/kWh, comparable to utility-scale solar, and 98-99% below the current US power grid at 0.4 kg/kWh.
We first looked at NET Power in a research note in 2019, exploring how next-generation combustion technologies could facilitate easier capture of CO2 (note here).
Levelized costs of power generation are estimated in a range of 6-8c/kWh, assuming $3.5/mcf hub gas prices (and by extension, $4.5-5.5/mcf input gas prices), in our model of NET Power’s oxy-combustion process linked here. The usual caveats apply that levelized cost calculations can be materially lower, or higher, in different contexts.
The patents give some helpful details on pressures, temperatures, heat exchange, Cp/Cv ratios, and innovations to maximize efficiency; including recuperating waste heat from the air separation plant (which produces the pure O2 for the combustion process) back into the CO2 stream. Details are in the data-file.
What challenges for super-critical CO2 Brayton Cycles? There are six core challenges with super-critical CO2 Brayton cycles. They are outlined in the data-file, along with our assessment of how NET Power addresses the challenges, based on its patents.
Can we de-risk Net Power’s technology? Our NET Power technology review shows over ten years of progress, refining the design of efficient power generation cycles using CO2 as the working fluid. The patents show a moat around several aspects of the technology.
Methane slip occurs when a small portion of natural gas fails to combust in a boiler, burner, engine or turbine, and instead escapes into the atmosphere. How much methane leaks? This data-file reviews technical papers. Methane slip is very low at gas turbines and gas heating (less than 0.1%), rising to 0.5 – 3% in cookstoves and some dual-fuel marine engines. However, the highest rate of methane slip occurs in flaring.
Methane slip is a category of methane leakage at the point of consumption. Specifically, methane slip occurs when natural gas is supplied to a boiler, burner, engine or turbine, but fails to combust, and instead, methane is released uncombusted into the atmosphere.
The purpose of this data-file is to review different technical papers into methane slip, in order to quantify the most likely methane emissions rates by end use category. Three general observations are that (a) methane slip at the point of end consumption seems to have been less well researched than methane leakage throughout the supply chain (b) there can be a wide variation in different studies’ findings and (c) studies with the most extreme results have tended to receive the most media attention (go figure).
Modern gas turbines in the power sector have the lowest methane slip, estimated at 0.02% on average, according to data accepted by the EPA and IPCC. In the best study that crossed our screen, researchers from Purdue, Harvard, Environmental Defense Fund and Scientific Aviation flew 23 flights over 14 natural gas power plants. Some of the readings in the study actually came in “negative”. I.e., the air above the gas turbines was depleted in methane relative to the broader atmosphere, which was attributed to “partial combustion of ambient CH4 in the power plant”. Very low rates of methane slip in natural gas power plants can be attributed to high temperatures and continuous combustion, or in other words, the thermodynamics of the Brayton Cycle. Although slippage rates are higher when turbines first start up, or when they are throttled aggressively in volatile power grids.
Gas heaters and boilers most likely have a methane slip rate of 0.1%. However, what stood out from our review of technical papers was the skew. One study reviewed the methane leakage from gas-consuming devices in 75 Californian homes, and found a median leakage rate of <0.01%, a mean of 0.136% and a maximum of 1.0%. There is almost certainly a “tail” of defective heaters and boilers that needs to be identified and repaired.
Marine engines are increasingly using LNG as a transportation fuel, where the chemical properties of natural gas result in 24% lower emissions than heavy fuel oil (data here). Around 700 LNG-fueled vessels are in use globally in 2022. The rates of methane slip are much higher in some of these reciprocating engines than in gas turbines. The reason is that each stroke of a reciprocating engine is discrete, with the chance for injected fuel to ‘hide’ in the cold spots of engine cylinders, or pass directly from the injection valve to the exhaust valve. However this is being addressed. Wärtsilä has reduced methane slip from its dual-fuel engines by 85% since 1993, from 16 g/kWh to 2-3 g/kWh and says the next generation of engines will slip 1 g/kWh.
The highest rate of methane slip is in natural gas flaring, where our mid-point estimate is around 3.5% of the gas, but some studies have estimated leakage rates as high as 10%. Especially during high wind speeds, there is a danger that methane escapes the flare, or worse, that the flare is blown out, like a kind of environmentally unfortunate birthday cake. Overall the data suggest that reducing flaring (e.g., via gas utilization) and improving flaring are the world’s ‘lowest hanging fruit’ to reduce methane slippage. Companies such as Capterio, Baker Hughes, Sensia and Cimarron Energy have developed interesting solutions.
This note explores an option to decarbonize global LNG: (i) capture the CO2 from combusting natural gas (ii) liquefy it, including heat exchange with the LNG regas stream, then (iii) send the liquid CO2 back for disposal in the return journey of the LNG tanker. There are some logistical headaches, but no technical show-stoppers. Abatement cost is c$100/ton.
This data-file tabulates the Oil Majors’ exploration capex from the mid-1990s, in headline terms (in billions of dollars) and in per-barrel terms (in $/boe of production). Exploration spending quadrupled from $1/boe in 1995-2005 to $4/boe in 2005-19, and has since collapsed like a warm Easter Egg. One cannot help wondering about another cycle?
The peer group comprises ExxonMobil, Chevron, BP, Shell and TOTAL, which comprise c10% of the world’s oil production and 12% of the world’s gas production. As a good rule of thumb, this group can be thought of as c10% of global production.
This peer group quadrupled its exploration expenditures, from $5bn pa spent on exploration in 1995-2005 to an average of $20bn pa on exploration at the peak of the 30-year oil and gas cycle in 2010-2015. Exploration spend ramped from $1/boe to $4/boe over this timeframe. It has since fallen back to $1/boe, or around $1bn per company pa in 2022.
The US has always been the most favored destination, attracting c25% of all exploration investment, both offshore (e.g., Gulf of Mexico) and increasingly for short-cycle shale. During the last oil and gas cycle, the largest increases in exploration investment occurred in Africa, other Americas, Australasia; and to a lesser extent in Europe and the Middle East.
One possible scenario for the future is that this peer group will continue to limit its exploration expenditures to the bare minimum, below $1bn per company per year, or below $1/boe of production; under the watchwords of “capital discipline”, “value over volume” and “energy transition”.
However, it is somewhat terrifying to consider that the industry needed to spend an average of $2.5/boe on exploration from 2005-2019 in order to hold its organic production “flattish”.
Under-investment across the entire industry may foreshadow a sustained shortage of energy, especially if 50% lower-carbon gas is intended to replace coal as part of the energy transition, per our roadmap to net zero, or more pressingly as Europe faces sustained gas shortages. Hence one cannot help wondering if industry-wide exploration capex in the 2020s and 2030s is going to resemble the 2000s and 2010s?
This data-files aggregates the Oil Majors’ exploration capex, across ExxonMobil, Chevron, BP, Shell and TOTAL disclosures, apples-to-apples, back to 1995.
Our roadmap to ‘Net Zero’ requires doubling global gas production from 400bcfd to 800bcfd, as a complement to wind, solar, nuclear and other low-carbon energy. This data-file quantifies global gas production forecasts by country, what do you have to believe about global gas reserves, and is there enough gas?
Global gas production already doubled in the c30 years from 1990-2019, rising at a 2.5% CAGR, which is the same trajectory that needs to be sustained to 2050 on our long-term energy market supply-demand balances.
Amazingly, from 1990-2019, global gas reserves increased from 4,000 TCF to 7,000 TCF, for a reserve replacement ratio of 190%, although the numbers have been cyclical and have fallen below 100% in recent years (chart below).
On our numbers through 2050, a reserve replacement ratio of 107% is needed, while the ‘reserve life’ (RP ratio) will likely also decline from around 50-years today to 25-years in 2050. Please download the data-file for reserve numbers and production numbers by country.
Onshore resource extensions are seen primarily coming from shale, with continued upside in the US, and vast new potential in the Middle East, North Africa and possibly even European shale as a way of replacing Russian gas.
Another offshore cycle is also seen to be necessary, discovering and developing an average of 45 TCF of offshore resource each year in 2023-2050. These are big numbers, equivalent to discovering a large new gas basin (e.g., an “entire Mozambique of gas”) every 3-5 years.
Our best guesses for how a doubling of global gas production might unfold is captured in this model of global gas production forecasts by country/region and global gas reserves.
Global methane emissions amount to 360MTpa. 40% is from agriculture, 40% from the energy industry and 20% from the landfill industry. Within energy, over 30% of the leaks are from coal, 30% are from oil, 27% are from gas, and 7% are bio-energy. This data-file provides context by quantifying some of the largest methane leaks of all time.
Our roadmap to net zero requires a reasoned, pragmatic focus on minimizing all methane leaks. Consider that 40% of global emissions are from agriculture. Precisely no one is arguing that the world should therefore dismantle the global agricultural complex, leaving 8 bn humans to subsist upon foraging. We need to find effective ways of minimizing and reversing the impacts of methane leaks. Our best single note on this topic is linked here.
What about super-emitters? Some sources have estimated that the worst 1-10% of leaks account for around 50% of methane leaked from the energy industry. Hence in this data-file, we have aimed to tabulate, and contextualize some of the largest methane leaks of all time. The recent Nord Stream 1-2 sabotage attacks in Europe are likely near the top of the list (chart below, left).
However, for context, the ongoing methane emissions from some of the world’s largest energy assets are likely even larger than the emissions from Nord Stream, or Aliso Canyon, or other famous blow-outs. The world’s largest oil field, or the world’s largest gas field each likely emit around 700kTpa of methane. This is because they are very, very large, producing 1%, 2% of the world’s total useful energy. Yet, on a per kWh basis, they are 10x less methane intensive than some of the methane-emitting coal mines plotted above-right.
Coal mines often leak more gas than gas assets themselves. One coal mine in Russia is said to be leaking 760kTpa. So, numerically, Nord Stream is not some kind of “climate bomb”, despite the media hysteria. This is all covered in our coal research.
In our view, one key reason to be unhappy about giant leaks like Nord Stream is not the volumes of methane being leaked. It is their pointlessness. It is pure environmental downside. At least coal mines produce coal.
Second, there are companies working hard to lower their methane emissions, especially in US shale. For example, they are replacing the pneumatic devices that tend to leak 0.01 – 10 Tpa of methane. Or they are deploying an incredible array of new sensing technologies, so they can immediately identify fugitive emissions sources, then remedy valves, seals, compressors, tanks, which in turn might leak up to 100 Tpa of methane when they fail. When faced with a choice, it would be nice if we could source supplies from ESG-positive suppliers, rather than wantonly leaky and ESG-negative suppliers.
The third reason to be unhappy about the Nord Stream 1-2 leaks is that they represent a direct attack on European infrastructure, further deepening what could be a decade-long energy shortage, a gutting of European industry. This also cements the likelihood that Europe will phase out all Russian gas by 2030, as it becomes ‘first in the firing line’ to be displaced by renewables.
An observation from compiling the data-set is that many methane-leaking events over the history of the industry are opaque. The methane leaked was never quantified. Or even today, it cannot be precisely quantified: estimates of the Nord Stream leaks range from 70kT to 500kT.
Finally, many regions with large-scale oil and gas production have no historical disclosure of large methane leaks. In our view, the most likely explanation is that the methane leaks have not been publicized. Consider, for example, that the US energy industry produces c20% of the world’s useful energy, but only c10% of the global energy industry’s methane emissions. The US is transparent. Methane leaks come to light. They get addressed. Perhaps you cannot say the same about all other countries.
Data. A useful resource estimating methane emissions, by country, by source, is the IEA’s methane emission database. The aggregation of individual large-scale leaks is our own.
Modelling Europe’s gas balances currently feels like grasping at straws. Yet this 10-page note makes five predictions through 2030. We have revised our views on how fast new energies ramp, which gas gets displaced first, which energy sources are no longer ‘in the firing line’, and gas pricing.
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