The U.S. has been at the forefront of international LNG trade since its inception. The first shipload of LNG was delivered by the Methane Pioneer in 1959 from Lake Charles, La., to Canvey Island, U.K..

Ten years later in 1969, the Kenai LNG plant in Alaska, owned by Phillips Petroleum Co. and Marathon Inc., shipped the first LNG cargo to Japan, opening up the LNG trade to Asia. The Kenai plant,small by today’s standards at only 1.5 million metric tons per year (mt/y) [equal to 210 million cubic feet per day (MMcf/d)], was the largest LNG plant at that time and continued operation until the final cargo was sent in 2015.

Those were much simpler times in the LNG business. Today, the U.S. is setting sail on its latest excursion into the global LNG export business, where there are much more complex negotiations and contracts, financing and fierce competition as natural gas demand is spurring growth in LNG supply.

“We tend to view things based on our supply and demand here, and what we can do as far as moving our gas outward. But I think that we have to look at and understand that there are other folks out there that have resources competing with the U.S.,” Bob Broxson, managing director in BDO’s energy disputes practice, told Midstream Business. “I think we have a great story to tell from a pricing and supply perspective, but we do need to be aware of what the competition is,” he said.

Greg Haas, director of integrated oil and gas for Stratas Advisors, agreed with the pricing perspective.

“For the LNG markets, we think it is a long-term trend that North American gas, including gas from Canada, will be at a significant discount and can be liquefied and delivered to consuming nations at lower costs than many competitors around the globe,” he told Midstream Business.

Shift in dynamics
The dynamics around how buyers seek to acquire LNG has shifted quite a bit. McKinsey Energy Insights conducted a survey of about 60 LNG buyers worldwide that account for about 85% of the global LNG, noted Dumitru Dediu, an associate partner in McKinsey Energy Insights’ Amsterdam office.

“We see there is a stronger preference for shorter term contracts, more innovative pricing formulas and a high demand for flexibility for these buyers,” he explained. “That demand is driven by a lot of non-traditional buyers, especially in Southeast Asia. That will account for about 50% of the LNG demand growth.”

To meet that LNG demand, a new round of construction worldwide is underway, with new final investment decisions (FIDs) being announced and new construction underway primarily in the U.S. Sorting out the complexities on the global stage of today’s LNG market will be the major task of producers, midstream pipelines, LNG plant developers, shippers and LNG buyers.

Price drives demand

A majority of contracts for LNG in Asia have oil-linked prices. Security was the main driver for countries like Japan and South Korea, which have little or no oil and gas resources. By paying a higher price, the countries wanted to assure energy security. However, that scenario is changing as seen by the preferences for shorter-term contracts and flexibility.

The U.S. is re-entering the world LNG export stage at a key moment in pricing history.

“There is an enormous resource base within the Lower 48, and U.S. Henry Hub operations are going to remain low for some time, we think,” said Neil Beveridge, senior analyst in AB Bernstein’s Hong Kong office.

With Henry Hub prices at $2 per million British thermal units (MMBtu) to $3/MMBtu, “you can get LNG delivered to the Pacific Basin for $8/MMBtu to $9/MMBtu,” he continued. “The biggest incremental buyer over the next decade is going to be China. China is going to account for over 40% of global demand growth.”

It is not only the price that will drive U.S. exports, but also current lower capital costs for construction. “For a period of three years, there was no North American LNG capacity that took an FID. The global LNG market was oversupplied and prices were low. There was big project capacity under construction. It wasn’t clear how much LNG the market was going to need and when,” noted Amber McCullagh with RBN Energy.

“What has happened over the last one to one and a half years is that construction costs have started to come down. The cost of delivering LNG is lower. We’ve seen a renewed interest in environmental goals. We’re seeing both an increased appetite for LNG globally as well as increased competition with other fuels. It could be coal displacing oil in power generation, or it could be backstopping renewables serving loads that previously came from coal or crude oil,” she added.

Haas pointed out that Stratas Advisors’ 2018 long-term price forecast for Henry Hub showed that it will take until 2031 for prices to double to about $6/MMBtu, which means a compound annual growth rate of 4.7% in prices from 2017 levels.

“In 2017 the gas price was $2.96/MMBtu. We get to $5.95/MMBtu in 2031. In 2040, we’re at $7.12/MMBtu,” he added.

54 possibilities
In June, the U.S. Department of Energy (DOE) released a study on “Macroeconomic Outcomes of Market Determined Levels of U.S. LNG Exports,” which was prepared by NERA Economic Consulting. Combining three U.S. supply cases, three U.S. demand cases, three international demand cases, and two international supply cases in all possible combinations yielded a total of 54 different scenarios for LNG exports.

“Under reference case supply assumptions, prices are much lower and in a more narrow range when international LNG demand varies. These central cases have a combined probability of 47% and prices range from $5/MMBtu to about $6.50/MMBtu in 2040,” according to the report.

“About 80% of the increase in LNG exports is satisfied by increased U.S. production of natural gas with positive effects on labor income, output and profits in the natural gas production sector,” the report added.

“LNG exports affect the U.S. economy in multiple ways. Their direct impacts are increases in natural gas production, LNG export revenues, wealth transfers in the form of tolling charges on LNG exports and domestic natural gas prices. Higher LNG export demand that leads to an increase in natural gas production to meet the demand puts upward pressure on the domestic wellhead and Henry Hub prices,” the report continued.

Chasing the prize

Almost every forecast of supply and demand for LNG through 2030 is the same—a gap of 100 MMmtpy to 120 MMmpty.

“Next year there is a lot of supply coming on the market principally from a lot of U.S. projects starting up,” said Bernstein’s Beveridge. “The longer-term picture is that the industry is not investing enough in new LNG capacity. We’ve been calling for the start of a new cycle since the start of 2018.

“We’ve gone through this period over the last few years worried about a gas glut. Now I think people are starting to worry about a gas deficit,” he emphasized. “There is a lot of capacity coming in 2018 or 2019, and 2020 looks okay as well. As we come into 2021, 2022 and 2023, there’s just not enough liquefying capacity being built. It takes five years to build a project. It is pretty clear there is going to be a supply deficit through the early 2020s.”

Beveridge added, “Over the next two to three years, assuming the global economy holds, which is looking like a greater risk, there will be a large number of projects move forward into construction.”

McKinsey’s Dediu noted that McKinsey’s Global Gas Outlook “shows there will be a gap of around 100 MMmtpy to 120 MMmtpy by 2030. It is a supply gap that we will need to fill with new projects. A large part of that will be built by Qatar, who announced an additional 33 MMmtpy with additional North Field expansion.

“About half of the supply gap will be filled mainly with projects that already should be competitive or taken up by buyers. The remainder of that will be filled with competition from other conventional projects and U.S. projects,” he continued.

Growth support
In its August investor presentation, Cheniere Energy Inc. stated, “Supply/demand fundamentals support continued LNG demand growth worldwide with forecast global LNG trade growth of more than 200 MMmtpy by 2030.

China remains the prize for LNG demand.

“We’ve got to deal with who is competing with us. You’ve got the Russians building a pipeline that will go to China. When we look at the number of customers out there that are actually buying LNG, we tend to focus on places like China obviously, but we have some hindrances to that right now,” Broxson said.

“But there are a lot of other places like Europe that are looking to have more competitive advantage as opposed to being tied to one supply out of Russia,” he added.

“Will we see China sign up for a material volume of U.S. LNG? It is going to be a very political question. If relations between the U.S. and China continue to deteriorate, then it is difficult to see Chinese companies signing up U.S. LNG,” noted Beveridge.

“On the other hand, if you think about the $300 billion to $350 billion trade deficit that the U.S. has with China, LNG could be a key part of that solution. If 20% of China’s gas needs by 2030 were supplied by the U.S., which would be around 10 Bcf/d to 12 Bcf/d, it could narrow that trade deficit by $50 billion over several years,” he explained.

Skirting the tariff

Much of the demand for LNG in China comes from the country’s effort to reduce air pollution in its major cities. China has expanded its Blue Sky policy, which will require additional LNG to replace coal.

One advantage that the major oil companies have over domestic producers is being able to source LNG from multiple countries. According to an October, article, ExxonMobil is actively pursuing business in China while expanding output in places like Papua New Guinea and Mozambique, an anonymous ExxonMobil manager told Reuters.

Exxon plans to participate in building an import terminal in Huizhou, China. While U.S. companies face a 10% tariff for LNG exports to China, ExxonMobil can deliver LNG to China from Qatar, Australia and Papua New Guinea with no tariff.

The Reuters article stated that ExxonMobil is among top-ranked companies in many industries that are focusing on China, regardless of the trade dispute.

Filling the gap

As of Feb. 26, 2018, DOE had received applications for a total of 55.04 Bcf/d of LNG exports to non-Free Trade Agreement countries. Again, there is virtually no chance that this level of LNG exports could be reached before 2040 and only a 2% chance that this level could be reached or exceeded by 2040, according to the DOE report.

At this time there are two U.S. LNG plants actively exporting LNG:

  • Sabine Pass in Louisiana; and
  • Cove Point in Maryland.

Four other facilities are under construction:

  • Freeport LNG and Corpus Christi LNG in Texas;
  • Cameron LNG in Louisiana; and
  • Elba Island in Georgia.

Cheniere’s Sabine Pass Trains 1 through 4 (18 MMmtpy) in the Cameron Parish, La., plant are in operation. Commissioning activities are underway on Sabine Pass Train 5 (4.5 MMmtpy). The company is progressing Sabine Pass Train 6 (4.5 MMmtpy).

Corpus Christi LNG Train 1 has an in-service date of the first half 2019 and Train 2, the second half . Train 3 is 30.1% complete with an in-service target of second-half 2021. The total for these three trains is 13.5 MMmtpy.

A Federal Energy Regulatory Commission (FERC) application was also filed for Corpus Christi Stage 3, a capacity expansion of about 9.5 MMmtpy adjacent to the Corpus Christi LNG plant.

“It is well understood that China needs more LNG over the long term. We view U.S. LNG as an important variable to help resolve trade issues as U.S. LNG into China is beneficial to both nations,” Jack Fusco, Cheniere’s president and CEO, said during the second quarter earnings call in August.. “China is an important growth market for Cheniere, and we continue to build and solidify relationships with key Chinese counterparties.”

In the first half of 2018, U.S. LNG exports increased 65% to more than 10.3 MMmt. The U.S. is now the fifth-largest LNG supplier. Australian exports were up 20% in the first half to more than 32 MMmt, Anatol Feygin, Cheniere EVP and chief commercial officer, said during the call.

“Despite more than 11 million tons of new supply added to the market in the first half of 2018, we’re seeing extremely strong demand mostly in Asia keeping the market tight. These price signals provide further evidence the market is calling for additional investment in liquefaction infrastructure,” he said.

BDO’s Broxson pointed out, “What Cheniere is doing is building some of their own pipeline facilities, basically to insure they can get gas to their facilities so they can remain competitive and have supply available. I think you’re going to see a lot of companies take on new pipeline positions.”

Storm delays
Freeport LNG’s inauguration was delayed due to flooding of its equipment storage yards during Hurricane Harvey in 2017.

“After all of our delays we are looking at startup for Train 1 in the third quarter 2019. Trains 2 and 3 are scheduled for startup in the first quarter 2020 and the second quarter 2020, respectively,” said Sig Cornelius, Freeport LNG president and COO. Each train has a capacity of 5 MMmtpy.

“We are progressing on our fourth train. We need to sell between 70% and 80% of the capacity to reach FID on that project,” he added.

Freeport LNG announced on Sept. 5 a binding heads of agreement (HOA) with Sumitomo Corp. of Americas to negotiate a liquefaction tolling agreement (LTA) for 2.2 MMmtpy for 20 years, which represents about 50% of capacity.

“We are planning to close on our commercial offtake agreements and get all of the regulatory approvals by early 2019. We are out for bids on the engineering, procurement and construction contract. We are targeting an FID on this project by mid-2019. If all that comes together, we would have commercial operations start up in mid-2023,” Cornelius continued.

Freeport has a tolling business model as a liquefaction facility.

“The tollers are responsible for arranging to bring gas to our facility so we take custody at the inlet of our pretreatment facility, and then we are responsible for loading it on the ships,” he explained. “We are very much aware of what the price for LNG is around the world and netbacks to the various markets, including shipping costs, gas costs and liquefaction costs. We have to understand the entire market.”

Cove Point
In April, Cove Point LNG became the second active U.S. LNG export facility. It has nameplate capacity of 5.25 MMmtpy. Thomas F. Farrell II, chairman, president and CEO for Dominion Energy, said in the company’s second-quarter report in August, “The Cove Point liquefaction project achieved commercial in-service early during the second quarter and since then has delivered 19 commercial cargoes representing over 60 Bcf of LNG.”

Farrell told Reuters in a June that “You’ll see a very significant increase in U.S. natural gas coming to Asia and in particular Japan.”

Dominion signed 20-year agreements for the plant’s capacity to GAIL (India) for 2.3 MMmtpy and ST Cove Point, a joint venture between Sumitomo Corp. and Tokyo Gas, for 2.3 MMmtpy.

Kinder Morgan Inc. said in its third-quarter 2018 earnings report in October that the first of 10 small-scale, modular liquefaction units is expected to be placed in service in first-quarter 2019 with the remaining nine units coming online throughout 2019. The total liquefaction capacity of the plant is about 2.5 MMmtpy at a cost of about $2 billion.

The project is supported by a 20-year contract with Shell. Elba Liquefaction Co. LLC is a joint venture between Kinder Morgan (51%) and EIG Global Energy Partners (49%).

Kinder Morgan has a second LNG project—Gulf LNG—near Pascagoula, Miss. In August, Gulf LNG Liquefaction Co. LLC, Gulf LNG Energy LLC and Gulf LNG Pipeline LLC received a FERC notice of schedule for environmental review. The final environmental impact statement will be completed in April 2019 and the final decision for issuance of the FERC certificate will be in July 2019.

Phase 1 of Gulf LNG will have a single train with a capacity of 5 MMmtpy. Phase II will add a second 5-MMmtpy train.

Lining up reserves

There are two basic business models for U.S. LNG projects. The first, as described by Freeport LNG, is a tolling model. The second is the Cheniere model of a full-service LNG operation offering that includes gas procurement, transportation, liquefaction and shipping.

Qatar Petroleum and Tellurian Inc. are taking a different tack on the gas procurement portion. The Qatari company plans to spend about $4 billion per year for five years in U.S. oil and gas fields, according to Some of that gas would likely supply the Golden Pass LNG export project.

Golden Pass Products, a joint venture of Qatar Petroleum and ExxonMobil, will operate the liquefaction facility. Golden Pass is fully permitted for LNG exports and is awaiting an FID. The project involves three trains, each with a capacity of 5.2 MMmtpy.

Tellurian is developing the Driftwood LNG project near Lake Charles, La. In a November 2017 press release announcing the closure of the acquisition of 9,200 acres in the Haynesville shale for $85.1 million, Meg Gentle, Tellurian president and CEO, said, “Acquisition of natural gas producing acreage in the core of the Haynesville provides the foundation for a growing portfolio of assets that we expect can produce LNG for a cost of $3/MMBtu, free on board U.S. Gulf Coast.

While U.S. companies continue to position themselves in the market, competition in the rest of the world is doing the same.

Canada enters the fray

The newest FID was taken by Shell Canada Energy and its joint venture participants for LNG Canada in Kitimat, British Columbia. The facility will consist of two trains with a total capacity of 14 MMmtpy with the potential to add two trains, according to an October Shell press release. Construction will begin immediately with JGC/Fluor as the EPC contractor.

With access to abundant, low-cost Canadian gas, the project has an additional benefit in that it is 50% shorter than the route from the Gulf of Mexico. TransCanada will build, own and operate the 402-mile Coastal GasLink Pipeline from the British Columbia fields to the plant. The project has a 40-year export license.

LNG Canada is expected to deliver Shell an integrated internal rate of return of some 13% with a significant cash flow at a gas price of $8.50/MMBtu delivered in Tokyo Bay. Total Western Canada gas resource has an estimated 300 Tcf at a cost below $3/MMBtu. Shell’s working interest in British Columbia’s Groundbirch production project is assessed to hold over 9 Tcf of recoverable resources with a cost of supply of around $2/MMBtu, explained Martin Wetselaar, integrated gas and new energies director for Royal Dutch Shell, in an October webcast.

“When compared to a typical greenfield development on the Gulf Coast, we expect LNG Canada to benefit, on average, from lower shipping costs of $1/MMBtu. In terms of the gas supply—including the cost of the pipeline—we expect to see on average a $0.50/MMBtu advantage,” said Jessica Uhl, Royal Dutch Shell CFO.

Swimming with sharks

Cheniere is leading the charge into international LNG markets with its Sabine Pass and Corpus Christi liquefaction plants. However, they are not the only sharks in the LNG ocean. The competition is reading the same price forecasts and supply demand curves.

Currently, Qatar is the leading LNG producer worldwide with 77 MMmtpy of capacity. With the addition of the Prelude and Ichthys LNG plants offshore Australia, that country will be new world leader with nameplate capacity of about 85 MMmtpy.

The U.S. is vying to be in the top three of LNG producers.

However, Qatar doesn’t want to relinquish its title as the world’s leading producer. The country announced it would build four new 8-MMmtpy LNG trains, which would increase its production to over 110 MMmtpy and return it to the No. 1 spot.

The company has been positioning itself for the coming competition for customers. As of last January, all of the ventures previously operated by Qatargas and RasGas are now operated by the “new” Qatargas, according to a Qatar Petroleum press release.

Qatargas announced in September, a 22-year sale and purchase agreement (SPA) was signed with PetroChina International Co. Ltd. for 3.4 MMmtpy. LNG delivery was set to begin in September 2018. The SPA will be supplied from Qatargas 2, a joint venture between Qatar Petroleum, ExxonMobil and Total.

This is part of a concerted effort by ExxonMobil to tap into the rapidly increasing Chinese LNG market. In addition to its Qatari project, the company has a 20% interest in Gorgon LNG in Australia as well as interests in a three-train (8-MMmtpy) expansion of Papua New Guinea LNG, and 3.4-MMmtpy Coral Floating LNG offshore and the 7.6-MMmtpy Rovuma LNG onshore Mozambique. Asia and Europe are the targets for all of those projects.

Anadarko’s plans
Anadarko Petroleum Corp. is working on signing SPAs to secure financing for its initial Mozambique two-train, 12 MMmtpy facility. In June, Anadarko announced signing an HOA with Tokyo Gas and Centrica LNG Co. Ltd. for 2.6 MMmtpy from startup to the early 2040s. In March, an SPA was signed with Électricité de France SA for 1.2 MMmtpy for 15 years.

“In Mozambique there is a significant LNG development that could be in very close proximity to a lot of customers that U.S gas would be vying for,” said BDO’s Broxson.

Shell and Equinor recommitted to the 10-MMtpy Tanzania LNG project.

Australia hasn’t given up either. Woodside and BHP are developing the Scarborough Field to supply gas for the 4 MMmtpy to 5 MMmtpy Pluto Train 2 with an FID expected in 2020.

Nigeria LNG is seeking $7 billion for the 8-MMmtpy addition of Train 7 to its LNG plant, bringing that facility to a total of 30 MMmtpy. An FID is expected this year.

Cross-border natural gas sales are expected to keep some LNG plants at full capacity. For example in August, the government of Trinidad and Tobago signed an agreement to purchase 150 MMcf/d of natural gas from Venezuela’s nearby offshore Dragon Field, providing much needed additional feedstock for the Atlantic LNG plant in Point Fortin, Trinidad, noted the U.S. Energy Information Administration.

Egypt has two LNG plants—Damietta LNG and Egyptian LNG—where production was curtailed due to domestic demand for gas. With gas feedstock from ENI’s Zohr and Nooros fields offshore Egypt, for example, the country could end imports sooner than first expected and increase the prospects of becoming a net exporter again.

In September, Noble Energy announced it had executed multiple agreements to support delivery of natural gas from the Leviathan and Tamar fields offshore Israel, which could also supply the LNG facilities. Production from Leviathan is scheduled to begin by the end of 2019.

Other projects and resources, such as Sempra Energy’s Energia Costa Azul LNG project in Baja California, the Russian Arctic 2 project, the Shtokman Field in the Russian Barents Sea with 130 trillion cubic feet of gas and offshore Africa, are still in the mix for meeting the expected LNG gap.

LNG heads East

Shipping costs from the U.S. Gulf Coast to Asia are among the highest in the world, costing about $2.20/MMBtu. With the opening of the new, expanded Panama Canal about two years ago, the distance to Asia was shortened and shipping costs were lowered to about $1.80/MMBtu, which is the cheapest route to Asia, said McKinsey’s Dediu.

“At the moment there is one slot per day for LNG. The projection is that by the end of the next decade there will be a need for about three or four slots per day,” he continued. “Generally what we see is the Atlantic Basin being a net exporter into the Pacific Basin. A lot of the cargoes will come from the U.S. Gulf of Mexico.”

The Panama Canal Authority introduced new rules in October, allowing two LNG carriers on Gatun Lake at the same time, although moving in opposite directions, and letting carriers travel at night. The number of slots was increased to two and will likely be bumped up to three slots in 2022.

Conventional LNG carriers can transit the canal. Only Qatar’s Q-Max and Q-Flex carriers cannot transit.

According to an April report from the Oxford Institute for Energy Studies, “The prospect of the Panama Canal becoming a bottleneck for LNG supply from the Atlantic Basin to Asian markets is a very real possibility.”

A single slot per day—with half of those vessels (empty) being return ballast voyages—would equate to 19.2 Bcm of LNG from the U.S. to Asia. Two slots per day would equal 38.3 Bcm, noted the study.

What goes around

The Kenai LNG plant was sold to Andeavor in 2018. Then Andeavor merged with Marathon Petroleum, and Kenai was back with one of its original owners—what goes around, comes around.

Although the Kenai LNG plant is no longer producing LNG, plans for another LNG plant near Kenai are underway. ExxonMobil, BP, ConocoPhillips and TransCanada selected a site in the Nikiski area on the Kenai Peninsula as the lead site for the proposed Alaska LNG project’s liquefaction plant and export terminal, according to an October press release.

The project concept includes a gas treatment plant on the North Slope, an 807-mile, 42-inch gas pipeline and at least five off-take points for in-state gas delivery. The plant would have a capacity of 20 MMmtpy. Total cost is estimated at $45 billiion to $65+ billion, acccording to Alaska Gasline Development Corp. (AGDC) and Alaska LNG.

AGDC, Sinopec, CIC Capital Corp. and Bank of China signed an agreement supplementing the joint development agreement signed in November 2017, according to an October press release. AGDC agreed to reserve 15 MMmtpy for Sinopec. In 2017, AGDC signed a memorandum of understanding (MOU) with Korea Gas Corp., an MOU with PetroVietnam Gas and a letter of intent with Tokyo Gas Co. Ltd.

“Alaska is a trusted source of LNG. For more than 40 years Tokyo Gas received shipments of LNG from Alaska. Alaska LNG is naturally an economic and reliable source of LNG for Tokyo Gas,” said Michiaki Hirose, Tokyo Gas president in a December press release.

“The Alaska project is much more like a traditional liquefaction project in East Africa, Western Australia, Siberia or the Middle East in that the projects have dedicated reserves, dedicated infrastructure and massive capital costs versus U.S. Gulf projects, which generally feature lower capital cost but higher variable costs,” said RBN Energy’s McCullagh.

“If you’re competing with the U.S. market for each Btu, Alaska does have some advantages in terms of its proximity to Asia, but Alaska LNG would pay the same tariff as Gulf Coast LNG. Alaska LNG seems to have more commercial alignment than it did two or three years ago.

“But the size of that project means that it needs to put together a bigger volume of SPAs for it to go ahead,” she continued, noting RBN Energy follows the intersection between the U.S. gas market and global LNG markets in its LNG Voyager newsletter.

Bernstein’s Beveridge emphasized that “Alaska seems an odd project to be pushing from a Chinese point of view. One possibility is the Chinese are focusing on Alaska because they know it is the one least likely to be built. One thing that does make Alaska different than a Lower 48 project is that you could see the project priced on an oil-linked basis rather than Henry Hub, which the Chinese may prefer over the long run.

“This is quite interesting because I think the biggest issue for Chinese buyers in regards to U.S. LNG is that when they are signing up for a typical U.S. LNG project, effectively they are making a commitment for hub pricing for the next 25 years. They’re basically locked into that spread between oil-linked prices and Henry Hub through to the mid-2040s,” he added.

Over the next 25 years, there is a possibility that prices could change significantly, making U.S. LNG exports not particularly attractive in regards to oil, he speculated. If Henry Hub prices stay low at $2/MMBtu to $3/MMBtu for the next three decades, any hub-linked prices will be the right choice. “But as we all know, in the past Henry Hub has been very volatile.”

Scott Weeden is a Houston-based freelance writer and frequent Hart Energy contributor specializing in energy issues