Mark Axford has more than 35 years of energy experience as an engineer,  product manager, sales and marketing executive, and independent consultant with Axford Turbine Consultants. For more information, visit Axfordconsulting.com

Mark Axford

Some people call it the Super Bowl of the energy world—this is the 41st year of the famous CERAWeek by S&P Global. Held March 10 – 14 in Houston, this year’s theme was multidimensional energy transition: markets, climate, technology, and geopolitics. Maybe too long of a title, but it’s hard to be brief about a conference that draws 9,000 attendees and more than 600 speakers from 80+ counties.

Bill Gates talked about a new modular nuclear power technology funded and ready for installation number one in Wyoming. Also on stage were the CEOs of ExxonMobil, Chevron, OXY, ConocoPhillips, Hess, TotalEnergies, Saudi Aramco, bp, Petrobras, Siemens Energy, Mitsubishi Power, Baker Hughes, Williams, Cheniere LNG, Bechtel … and the list goes on. 

Each participated in panel discussions and one-on-one interviews with Dr. Daniel (“Dan”) Yergin, author and co-founder of CERAWeek. There were also international government officials, including Danielle Smith, Premier of Alberta, Canada, and the ministers of energy from Kuwait, Brazil, Abu Dhabi, and beyond. The discussions ranged from oil and gas markets, renewable energy, climate change, battery storage, and electric cars.

Dr. Dan Yergin- Co-Chair and Founder, CERAWeek by S&P Global

But there was an elephant in the room that kept popping up in every discussion: artificial intelligence (AI)—the effect of AI on all aspects of the energy business. Numerous U.S.-based utilities got a surprise during the course of 2023: Their forecasts for future electricity demand required large revisions due to the explosive growth of AI data centers.

Data centers have been around since the late 90s as passive warehouses to store customer data for banks, Amazon, and the like. But there is a new breed of data centers for AI applications. The AI data center is more than a warehouse; it utilizes data as input to MANUFACTURE an intellectual product. The sophisticated chips made by NVIDIA run faster and hotter and consume five times more electricity, much of it for cooling, as a legacy data warehouse. These AI data centers run 24 X 365 baseload and demand high levels of reliability. They tend to be located near metropolitan areas that have strong fiber optic infrastructure.

Loudon County, Virginia has the largest AI data center concentration in the world. It is served by Dominion Energy who is racing to get additional gas turbine generators installed. Dallas and Atlanta also have attracted large numbers of AI data centers. Georgia Power, the utility that serves metro Atlanta, recently stunned regulators when it disclosed a huge correction to its load forecast pointing to AI data centers as the main culprit.

In 2024, about 18% of total personal computer shipments globally will be AI-capable PCs, and this will only be the start of a major market transition, according to research firm Canalys. Graph Source: U.S. Energy Information Administration and Georgia Power. 

Many big cities are now pulling back the economic incentives previously provided to attract data centers. Soaring power consumption is also delaying coal plant closures in Kansas, Nebraska, Wisconsin, and South Carolina.

You might say there was a second elephant in the room: The recent “pause” to the permitting of new LNG export facilities by the U.S. Department of Energy (DOE). With the United States now being the largest producer of LNG, all the major players were in the auditorium listening to U.S. Secretary of Energy Janet Granholm explain that the Biden Administration’s pause should be “well in the rearview mirror” by early 2025. She said the pause was called for “in order for our DOE labs to conduct a data-based assessment of what further expansions of U.S. exports mean for our climate, for global energy, for national and global security, our allies and for domestic prices.”

The audience was not impressed, especially Senators Joe Marchin and Dan Sullivan. “The pause ought to be paused immediately.” A pause cannot be called temporary if it has no end date—that’s a freeze.

U.S. Senators Joe Manchin (WV) and Dan Sullivan (AK)

Interesting to note that on March 22, the last day of the conference, 16 U.S. states filed suit against the U.S. government stating, “The LNG export ban is not justified by any statutory authority and thus is beyond the President’s powers,” and stating that the ban is “arbitrary and capricious” and “unconstitutional.”

Among the 16 governors signing the lawsuit was Alaskan Governor Mike Dunleavy. Dunleavy was concerned that without an immediate reversal of the pause, buyers of U.S. LNG would worry that purchasing it could be affected by future presidential edicts. Indeed, within days after the pause was issued on Jan. 26, the country of Qatar announced funding for a major expansion of its LNG export complex. In addition, Russia announced to Europe the availability of additional LNG supply.

Dunleavy noted that Alaska is developing a US$43 billion LNG export terminal near Anchorage and while it is not directly affected by the pause, the quest for private financing will be damaged. Dunleavy has also been frustrated by questionable restrictions placed on drilling and exploration for minerals on federal land in Alaska. He summed it up by saying, “This won’t be cleared up for Alaska unless Donald Trump is re-elected.”

No surprise that many aspects of energy policy in the United States and other countries are often at the top of the political agenda.

Articles

The blockbuster event tackled energy and power markets, supply chains, net zero, and beyond, but the biggest surprise may have been artificial intelligence. 

CERAWeek 2024: Houston Energy Conference Draws Thought Leaders on Climate Change

CERAWeek by S&P Global 2023, held in Houston, Texas, March 6–10, hosted more than 7,200 delegates and 1,000 speakers from 90 countries. The attendance smashed the previous high watermark of approximately 6,000 delegates set in 2022.

This conference is often referred to as the Davos of the Energy World. Keynote speakers included the CEOs of Chevron, Exxon, Total, OXY, Hess, and Cheniere, as well as the U.S. Department of Energy Secretary Jennifer Granholm and U.S. Senators Joe Manchin and Lisa Murkowski. But the wizard behind it all, Dan Yergin, the founder of CERA in 1983, provides the perspective and insight that draws the crowd.

Looking back one year, the two biggest events affecting the energy world have been:

The ongoing war in Ukraine and the related destruction of the Nord Stream Pipelines during September 2022. The short-term and long-term effects are being felt beyond Europe as energy markets for oil, gas, and LNG are truly worldwide.

The U.S. Inflation Reduction Act passed into law by President Biden on Aug. 16, 2022. This legislation included $369 billion in green energy grants and subsidies to accelerate the reduction of carbon in the energy mix. The Inflation Reduction Act is the Big Kahuna of funding that was the talk of the conference.

Over the years, the big topic of discussion has evolved from global warming to climate change and now to the energy transition. Yergin pointed out that this is not our first energy transition. “The first energy transition was from wood to coal in the 18

 century in Britain, as the cost of wood had gone up. But it emerged as a distinctive industrial fuel only in January 1709 when English metalworker Abraham Darby proved that coal was a more effective means for iron production than wood.

Energy transitions have hardly been swift. Although the 19th century is known as the “century of coal,” that century actually still ran, in the words of energy scholar Vaclav Smil, on “wood, charcoal, and coal residues.” It was not until 1900 that coal supplied half the world’s energy demand.

Oil was discovered in the United States in 1859. More than half a century later, on the eve of World War I, Winston Churchill directed the conversion of the Royal Navy from coal to oil for technological reasons—speed, flexibility, ease of refueling, and the elimination of crews shoveling coal. But it took until the 1960s, a century after it was discovered, for oil to overtake coal as the world’s number-one energy source.

Until now, energy transitions have unfolded over long periods of time. They have really been energy additions rather than transitions. Meanwhile, in the six decades since oil overtook coal as the world’s number-one energy source, the global consumption of coal has almost tripled.

The current climate-driven energy transition is meant to be achieved quickly—in fewer than 25 years. And it is meant to be transformative. Coal is to disappear, and the European Union anticipates that hydrogen will provide 25% of its total energy by 2050. Yet hydrogen provides less than 2% today.

The push toward a decarbonized future faces a dilemma. As it involves the balancing of three elements, it is being called the energy trilemma.

There must be a reliable supply of electricity and other primary energy sources to carry out our lives efficiently and without frequent interruption.

 That the sources of energy can be produced continuously without causing undo harm to the environment of our planet.

As we attempt to transition from carbon-based fuels to other energy sources, will the result be affordable to individuals in both advanced and developing countries and preserve a suitable energy foundation for what today is a $100 trillion global economy?

The pressure has increased to accelerate many of the 2050 carbon emission targets toward 2030. But it sometimes seems that the scale of what is being attempted is underestimated. Huge increases in the annual production rates of lithium, copper, and other minerals will be needed to make these transitions.

Yergin refers to this as one of the “bumps in the energy transition.” The faster we try to proceed with a transition from gasoline to electric cars and natural gas fuel to hydrogen fuel, the more potential there is for damage to the affordability component of the trilemma.

There has not been ample time for innovative technology to evolve that reduces the cost of mining, processing, and manufacturing the new fuels and materials that are needed for a smooth transition.

For example, technology exists to capture carbon from the exhaust stack of a coal-fired boiler or from a gas turbine. But currently, the process is not affordable. A new process called direct air capture is evolving that breathes in atmospheric air and directly removes CO

 for injection into a cavern or an oil and gas formation. Occidental Petroleum (OXY) made a major announcement at the conference of its investment into direct air capture. OXY likes the modularity of direct air capture and has the opportunity to build plants at locations where CO

 is needed, specifically at an oilfield that can boost production when injected with CO

. This idea might not appeal to some of the green energy proponents who would prefer to avoid any utilization of CO

 that produces more oil and gas even though it brings about a net reduction in CO

Caption: Largest coal-consuming countries statistics in exajoules. Credit: Axford Turbine Consultants

Technologies like carbon capture and hydrogen production are supported by the Inflation Reduction Act. As soon as it was signed into law, the wheels of investment started turning rapidly. During the balance of 2022, more than $50 billion of its funding was committed to projects. The big winners have been wind, solar, and hydrogen projects.


Green hydrogen, in particular, has gained tax credits that can be “stacked.” This means than credits can be earned for a wind farm or solar project that makes electricity for an electrolyzer to produce green hydrogen. In addition, credits can be earned for investment in the electrolyzer as well as a payment of $3/kg for the hydrogen produced. But the current cost of industrial H2 today remains very high: 90 cents/kg.

The goal of reaching net-zero CO

emissions by 2050 seems unrealistic. While the EU and the United States are making huge financial investments, how do we tackle global CO

 emissions when China and India, the two largest coal-consuming countries, are not on board? In 2022, China approved for construction 106 GW of coal-fired power at 22 sites. Compare China’s annual new coal construction (106,000 MW) to 2022 worldwide orders of natural gas-fired turbines (49,000 MW).

Imbalance among the legs of the energy trilemma has brought about a transition from natural gas to hydrogen yet more new coal is being added to the worldwide energy mix. Why? Coal-fired power wins the affordability leg of the trilemma in many regions of the world despite a lack of subsidies.

Security, sustainability, and affordability comprise the energy-transition trilemma discussed at CERAWeek 2023.

CERAWeek Charts Out the Energy Transition

After two consecutive years of virtual conferences, the 40th consecutive year of
CERAWeek 2022 by S&P Global rolled into Texas with a lineup of the world’s top
energy executives, ministers, and senior officials. How ironic that on the evening before the conference opening, Brent Crude rose more than $20 per barrel to $135, a 15-year high as the war in Ukraine escalated. The spot price of LNG in Europe had also soared to $140 per million Btu.

CERA’s founder Dan Yergin began the event by interviewing John Kerry, Special Presidential Envoy for Climate and Darren Woods, CEO of Exxon Mobil. In light of recent events, any scripting or planned questions were discarded. Everyone wanted to debate the pros and cons of placing heavier sanctions on Russia. Should the U.S. place an embargo on all Russian oil imports? Should President Biden revitalize the Keystone Pipeline? Should the restrictions on U.S. oil and gas production be lifted and should the policy of delaying review of pending LNG plant applications be changed to fast track?

The takeaway from the debate: No matter where you stand on climate change, a clash of philosophy has been brought to head by the war in Ukraine:

Leave oil and gas in the ground as the best approach to prevent an increase in atmospheric temperature greater than 1.5◦C by 2050 versus,

We cannot afford the huge short-term cost of the accelerated ramp rate to net-zero carbon emissions, which places little value on energy security.

Major international oil companies have set up separate business operations to tackle climate change. They see an opportunity to diversity into a profitable new market.


The production of oil and gas in and of itself does not have a negative effect on the atmosphere. it is the combustion of hydrocarbons that create most of the greenhouse gas. If carbon capture could be integrated into new power plants, that might be a satisfactory technical solution and perhaps less expensive than building out solar power and green hydrogen.
“Perfect is the enemy of good,” said Tengu Muhammad Taufik, CEO of Petronas, the national oil and gas company of Indonesia.

The technology to make carbon capture and storage affordable requires great scale and project management. Who better to handle large-scale projects relating to hydrocarbon processing that privately funded international oil companies? All they need is the right political signals and the opportunity to earn a profit.

Mike Wirth, CEO of Chevron, stated the goals simply: “Higher returns, lower carbon.”

The consensus amongst the experts: Without carbon capture being part of the solution, the goal of limiting atmosphere temperature rise to 1.5◦ C will not be achievable.

Houston welcomes CERAWeek 

The various divisions of the U.S. grid. ERCOT is not connected to the other regions

On Wednesday, Feb 10, 2021, it became apparent that a polar vortex (formerly known as winter) storm approaching Texas would likely cause plenty of pain. The Electric Reliability Council of Texas (ERCOT) issued an advisory warning to all generators to prepare for extended freezing weather. On Friday, the governor of Texas declared a state of emergency for all 254 counties. Spot prices for natural gas climbed as did the wholesale price of electricity.

As temperatures continued to drop on Saturday and Sunday, demand for natural gas and electricity soared. Freezing problems began to affect production at wind farms as well as natural gas wells and processing plants handling wet gas. The first trip of a thermal plant occurred on Saturday afternoon. By Sunday night, 14 Feb, electricity demand exceeded the previous all-time winter record of 65,915 mw set on 18 Jan 2018.

Generating units of all types (gas, coal, renewables, nuclear) began falling out of service on Saturday. At 10:30 PM Sunday, one of two nuclear reactors located near Corpus Christi tripped offline, a 1,200 MW forced outage. ERCOT initiated rolling blackouts to prevent a blackout of the entire Texan grid. Should a complete grid collapse occur, it can cause extensive damage to transmission lines and connected equipment. That would add weeks or even months to arrive at a full recovery. The decisive action to quickly implement load shedding avoided such a grid collapse with only a few minutes to spare.

During the next three days, supply did not come close to meeting demand. The shortfall exceeded 20,000 MW at times. By Thursday, some of the forced outages at generation plants had been resolved. Higher temperatures enabled the rolling blackouts to be shortened or eliminated. Power had been fully restored to most customers by Friday 19 Feb except a few isolated areas where had damaged distribution lines.

The Texas grid does not fall under the authority of the Federal Energy Regulatory Commission. Most Texans like it that way. Feds in Washington D.C. don’t. This wiring diagram was created during World War II as protection from any event that could possibly take down the electric grid of the entire country.

After the storm, some floated the notion that if ERCOT had been electrically connected to the Eastern and Western grids, power could have been imported to avoid blackouts. This is false. The regions of the grids adjacent to ERCOT were also affected by the storm. They incurred shortages of natural gas and rolling blackouts. There would have been no power available to import.

Fossil fuels are a big part of the Texas economy. For 20 years, they that have felt the squeeze as renewable energy has grown to generate approximately 25% of the electricity in the state. So it would be convenient for fossil fuel advocates to blame the problem on the highly diminished output of wind and solar generation during the storm. Indeed, wind turbines were shut down due to freezing and solar panels contribution fell to almost nothing due to cloudy daytime conditions along with snow and ice. But there is plenty of blame to go around, too, for thermal plants including gas, coal and nuclear that produce the other 77% of the power.

The facts are that the thermal fleet was not properly winterized. Why not? One possible explanation is that during 2020, the winterization inspections called for by ERCOT were done virtually instead of in person. Another possible explanation is that the process of winterizing a thermal plant causes some reduction in performance during the summer months. Most generation in Texas is privately owned with financial results normally pegged to performance during the hottest days in June-Sept. Therefore, there is a natural bias for asset managers to be more highly focused on summer instead of winter.

A brief word about wind turbines and freezing. The 4 big wind OEMs are Siemens, GE, Mitsubishi and Vestas. Each offers a “cold weather package” as an option for purchasers of wind turbines. The blades can be made out of special materials, the gear boxes are better insulated, and a higher grade of lubricants is utilized. But this can increase the capital cost of the wind turbine by 10-15%. Given the relatively warm climate of Texas, most wind farm developers decided not to purchase the cold weather package. Keep in mind that during normal winter conditions, power prices in Texas are low. The economic decision to use the low-cost design generally made sense. But don’t be surprised if there are a lot of cold weather retrofit kits installed on wind turbines during the spring and fall of 2021.

In summary, politicians will hunt for a scapegoat to serve their narrative. The ERCOT grid works well with renewable energy producing about 25% of the electricity. But increasing the renewable component much further may not be practical. Bulk storage of electricity via batteries is still uneconomical, without huge subsidy, when compared to storage of fuel in a coal pile or gas/oil in a tank at the site of a thermal plant. The state of Texas has added approximately 4 million residents since 2010. It seems that more generation of all types will be needed with greater attention given to winter readiness.

The ERCOT grid in Texas works well with renewable energy. But increasing the volume of renewables further may not be practical. More generation of all types and greater attention to winter readiness is needed. 

Who is to blame for the Texas grid outages?

SOARING PRODUCTION IN THE PERMIAN BASIN OF WEST TEXAS IS DRIVING DEMAND FOR TURBOMACHINERY, PIPELINES AND LNG EXPORT TERMINALS

The annual CERAweek (Cambridge Energy Research Associates) conference by IHS Markit in Houston during March drew attention to soaring oil and gas production in the Permian Basin of West Texas. This boom, now

in full swing, has been heralded as the “Second Wave” of the shale revolution in North America.

New fracking and drilling techniques are further reducing the time and cost to complete a well and produce a barrel of oil. The volume of associated natural gas is enormous, far beyond the U.S. domestic needs. LNG export terminals never imagined only 10 years ago are sprouting up on the Gulf Coast of Texas and Louisiana.

In the first quarter of 2019, Permian production of light crude oil exceeded four million barrels per day (MBPD) for the first time. More than 110,000 wells have been drilled there since 2010. As a result, the U.S. surpassed Russia and Saudi Arabia to become the world’s top oil producer. But current pipeline capacity cannot transport all the oil and gas to where it needs to go. Massive infrastructure investment is needed to support the bonanza. When critical pipeline projects are completed over the next couple of years, Permian oil production is predicted to climb

A great many gas turbines and centrifugal compressors are being ordered and built to support oil and gas in this region:

• Midstream facilities to process the associated gas and capture the valuable propane, butane and ethane fractions used for plastics production

• Trailer-mounter gas turbine gensets as a source of power at fracking sites

• Pipelines and compressor stations to deliver methane gas to customers

• LNG terminals with huge compressors to liquefy methane gas for export

Cheniere Energy revolutionized the U.S. natural gas business. It foresaw a vast surplus of natural gas being created by fracking and made a bold decision: change its existing LNG import terminal at Sabine Pass, LA into an export terminal.

In February 2016, the first tanker ofLNG to be exported from the U.S. was shipped from the Sabine Pass terminal. To date, more than 500 cargoes have been delivered to customers around the world. Sabine Pass has an export capacity of 27 million metric tons per annum (MMTPA). In late 2018, Cheniere began shipments from its second LNG export terminal (13 MMTPA) at Corpus Christi, Texas. The Dominion LNG export terminal in Maryland has also opened (5 MMTPA). The Freeport, (15 MMTPA), Cameron (12 MMTPA), Magnolia (8 MMTPA) and Elba Island (2.5 MMTPA) projects are under construction. More export terminals are in the advanced planning or early construction

GE has succeeded in having its gas turbines specified for most of the Gulf Coast LNG refrigeration compressor trains. The GE Frame 7EA gas turbine was selected for the largest trains, and GE also earned big LM2500+ and LM6000 aeroderivative orders for medium-sized LNG trains. Solar Mars units were selected for Kinder Morgan’s Elba Island terminal. Siemens has received an order for four SGT-750 compressor sets for the Magnolia LNG plant. Outside of the U.S., GE has been selected to supply LMS 100 gas turbine compressor sets for Canada’s first major LNG export terminal, now in construction in British Columbia.

Mitsubishi Hitachi Power Systems (MHPS) is a recent entrant into the LNG game. Its two-shaft H-100 gas turbine,

rated at 120 MW, has been qualified by ExxonMobil, Shell, Total and Bechtel for mechanical drive. The H-100 has been selected by Exxon-Mobil for a multi-train LNG liquefaction plant in Mozambique. It will drive centrifugal refrigeration compressors manufactured by Mitsubishi Compressor Corp. The Mozambique project is awaiting a final investment decision by ExxonMobil.

Mark Axford is President of Axford Turbine Consulting, which offers services to customers including

selling, sourcing, appraisal , valuation, forecasting and market analysis. For more information, visit axfordconsulting.com

LNG BOOM DOMINATES THE CERA CONFERENCE

CYCLING, LOAD FOLLOWING AND RENEWABLE FOLLOWING ARE NOT THE SAME

LM6000 gas turbine (GT) genset is in service at the North Pole power station in the City of North Pole, Alaska. It is a suburb of Fairbanks in Central Alaska and home to the Golden Valley Electric Association (GVEA). Running an electric company in Alaska is far from easy. The state population is 740,000, and about 400,000 live in metropolitan Anchorage.

Unlike the lower 48 states, there is not much of a transmission system to move electricity around. There is only one major transmission line in Alaska: The Alaska Railbelt Intertie. This 138kv intertie connects Fairbanks to Anchorage, 170 miles south. It can flow electricity in either direction but has a capacity of only 80 MW.

From an electrical standpoint, Alaska looks like a collection of small islands, each needing to be self-sufficient. GVEA owns six power generation plants, with the North Pole plant as the system hub. It is located adjacent to a refinery that provides diesel fuel, gasoline and jet fuel to Central and Northern Alaska.

In 1976, a pair of GE Frame 7B GT gensets, 60 MW each, were installed as base-load simple cycle units. The 7Bs are still operated today at a capacity factor of about 25%. They have been outfitted with recuperators to improve their efficiency from 25% to 37%. In 2006, GVEA also installed a one-on-one LM6000PC combined cycle unit for base load operation. The steam turbine was oversized in anticipation of a future addition of another LM6000PC.GVEA’s peak load is 230 MW.

“Our peak happens every year on Thanksgiving,” said Paul Morgan, GT plant manager at North Pole. “The delivery of 230 MW requires all three gas turbines, the 28 MW steam turbine, and some imported power from the Anchorage/ Fairbanks intertie.”

All of the GTs at North Pole use liquid diesel or naphtha fuel, which can be expensive. Two other GVEA plants add some fuel and cost diversity to the generation mix: A base load 75 MW clean coal plant at Healy (1998) and the Eva Creek 24 MW wind farm (2012).

The wind turbines have an annual capacity factor of about 33%. While the wind turbines have produced fuel cost savings, they triggered increased maintenance costs on the LM6000 because the operating regime of the LM6000 changed from base load to renewable generation following. After years of steady and reliable operation, the LM6000 has required five combustor change outs since 2014.

“We operated at base load on naphtha for six years and never experienced any premature hot section damage,” said John Kelly, GT plant foreman. “We did our hot section replacements at 16,000 hours every time.”

But soon after wind turbine following began, the hot section experienced severe swirler damage. Ever since then, the plant has seen anywhere between 2,000 to 8,000 hours between hot section intervals. Combustion swirlers pre-mix the fuel and air prior to delivery into the combustion zone.

With renewable generation following, GVEA has observed erosion of the swirlers. If not caught in time, the erosion can cause swirler pieces to break off. On one occasion, a liberated swirler piece caused extensive damage to the high-pressure turbine. TransCanada Turbines and GE worked closely with GVEA to understand the root cause of the problem.

To most power plant operators, cycling means the starting and stopping of a generating unit. Each start from cold (or warm) condition to full heat condition is one thermal cycle. Another cycle is incurred when the genset is shutdown.

Aeroderivative GTs, such as the LM6000 have been favored for many years by utilities that expect daily starting and stopping during the winter and summer peak seasons. Aircraft engines are designed for this purpose as commercial airlines fly several flights per day. Generally speaking, aeroderivative gas turbines incur less cycling-related maintenance than heavy frame gas turbines.

Load following is another operating mode. For utilities not connected to a larger grid, GTs are often used to follow the hourly changes in customer load. GTs are better suited to handle load following than coal or nuclear plants. The change in load is normally gradual and predictable: Higher load during daytime, less load at night.

Also, there are rarely huge changes on a minute-to-minute basis. But with the increasing popularity of wind turbines and solar generation, renewable following is showing itself to be a tougher challenge. Depending on cloud motion and other weather conditions, wind farms and solar power output can change in a matter of seconds.

GTs are called upon to react to this sudden supply change. GVEA has seen its LM6000 ramped up and down between 25 MW and 50 MW dozens of times per day. It would be incorrect to call this cycling or load following. Simply put, renewable following is a whole new type of torture. Who pays?

The answer for GTs required to follow renewable generation may be a new recipe for the swirler and combustor coatings. Or it may be an advanced control system that can change the acoustic signature of the combustion components when high stress is detected.

This problem must be solved as renewable following is not limited to small utilities operating as islands. Many large combined cycle plants rated in the 500 MW to 1,000 MW range were constructed for baseload operation, and are now being impacted by the presence of renewables. Some have already been forced into a new operating regime including being shut down every night and most weekends.

And now they have to deal with renewable following during daylight times. Who pays for the additional maintenance incurred by GTs when new renewable plants are connected to the grid? This is an issue that has to be solved if the viability of many GT plants is to be preserved.

CYCLING AN LM6000 AT A POWER PLANT IN NORTH POLE, ALASKA

On February 2, 2016, Mexican President Enrique Peña Nieto received the lifetime energy achievement award at Houston’s 35th annual IHS CERAWeek, an event described as the Davos of energy policy worldwide. “No country has more profoundly modernized every aspect of its energy sector, from oil and gas, to power and renewable energy, to the sale of refined products, in such a short time,” said Daniel Yergin, conference chair and vice chairman of IHS. These changes are bringing lower electricity prices to the Mexican people, said Yergin, and promise to capture the best technologies to restore Mexico’s position as a world leader in oil and gas. “We honor President Enrique Peña Nieto for making this transformation real.”

The 49 year-old president took office on December 1, 2012 vowing to breakup the government-owned energy monopolies and introduce competitive markets. To many, these goals were met with skepticism. For one thing, changes to the Mexican energy policy require an amendment to the constitution. But in December 2013, a constitutional amendment was approved by the Mexican government, allowing major changes to the oil & gas sector and electricity markets unleashing a wave of capital investment. “With this reform,” said Peña Nieto, “the Mexican State maintains the ownership of the underground hydrocarbons and, at the same time, it allows private participation in the entire hydrocarbon value chain and practically all of the electricity industry.”

Much of the change is linked to integration of the Mexican and Texan energy markets. This includes natural gas exported from Texas into Mexico via pipelines owned and operated by private investors. High-voltage DC interconnections with the Electric Reliability Council of Texas are also being developed along with a new 272-mile transmission line, privately funded at $1.2 billion. Mexico’s Secretary of Energy, Pedro Joaquin Coldwell, explained how the reforms have affected the hydrocarbon production and power generation sectors. “We had lost more than 1 million barrels per day of crude production over the last 10 years and our electricity rates were on average 75% higher than the U.S.,” he said. “Mexico could not continue with a system that gave exclusive investment rights in the energy sector to its own government.”

The reforms focus on transparent competitive bidding and contracting to show the finance community that production sharing contracts are competitive in the international context. This is resulting in surging gas turbine sales. According to McCoy Power Reports, last year more than 5,000 MW of gas turbine generator equipment was placed on order for job sites in Mexico (Figure).

Mexico has also embarked on a plan to build 10,000 km of natural gas pipeline infrastructure, more than twice as much pipeline capacity as has been built in the nation’s history. Six new pipelines are being connected to Texas and two more are authorized for construction. The change for Mexican consumers is marked. During 2013, natural gas was rationed. Today, there is plenty of economically priced gas available from Texas. This is enabling the acceleration of power plant conversion from oil-fired simple cycle to natural gas-fueled combined cycle.

Mexico is also increasing the electrical connectivity of its transmission system to Texas to facilitate the bi-directional flow of electricity between the countries. But U.S. export barriers (physical DC ties and political permits) will need to be tackled first to increase U.S. sales of electricity to Mexico during periods of ample supply in Texas. Peña Nieto also announced that during the first week of December 2016, Mexico will call for bids relating to production sharing of the deep water oil and gas deposits in the Gulf of Mexico. These activities promise to make Mexico a vibrant market for gas turbine power generation and compressor drive equipment.

(Mark Axford is a consultant to the turbomachinery industry.)