From our friend, Larry Persily, here are the latest news links of interest to our readers:

Oil and gas news briefs for June 16, 2016

LNG producers may need to curtail supply if prices fall further

(Australian Financial Review; June 16) – One of the world’s energy experts has suggested that some of Australia’s liquefied natural gas producers may have to mothball capacity as the Asian market becomes awash with supply and spot prices collapse further. Fereidun Fesharaki, chairman of London-based consultancy FGE, is predicting that the price weakness that will be most severe in 2018 will affect some U.S. export plants and potentially two coal-seam gas liquefaction trains in Queensland, Australia.

Some producers may be forced to share losses from reselling contracted LNG into the spot market, he said. “Somebody has to lose a lot of money — there is no escape from it — the question is how do you divide the losses,” said Fesharaki, a former energy adviser to the prime minister of Iran who is known to have close links with LNG buyers. The bleak outlook is based on expectations of a prolonged glut in LNG, made worse by large amounts of contracted output that has yet to be sold to end-users of gas.

“For the LNG market we don’t see a correction quickly, it will take many, many years,” he said, forecasting a “sloshing around” of the market lasting up to 2025 unless capacity is shut in or demand stimulated. FGE calculates that at least one-third of globally traded LNG is still looking for an end-market, based on gas in Australia, the U.S. and Qatar that has been sold to intermediate players that still need to sell it to actual users. “We say 2018 is the year that spot prices will hit the floor,” Fesharaki said. “We are saying $3.50 will be the annual average [in 2018], but during the year it is going to hit $3.”

South Korea to allow competition in LNG imports starting 2025

(Platts; June 14) – South Korea will allow local private companies to import LNG and resell it in the domestic market starting in 2025, bypassing state-owned Korea Gas, the Ministry of Trade, Industry and Energy said June 14. KOGAS has had a monopoly in LNG imports and domestic sales since its establishment in 1983. The government in 1998 allowed local companies to import LNG directly, but on the condition they use the imported gas for their own power production, not resell it in the domestic market.

Only Posco and SK E&S are importing LNG directly at present and they use it for power generation. Posco, the country’s biggest steelmaker, has been importing 550,000 million metric tons of LNG per year from the BP-led Tangguh consortium in Indonesia since July 2005 under a 20-year contract. SK E&S, South Korea’s biggest city gas provider, has been importing 600,000 tons of LNG per year directly from Tangguh since 2005 under a 20-year contract.

“Due to the monopoly and lack of competition, KOGAS and local companies have less motivation to look for cheaper supplies and respond flexibly to market conditions,” the ministry said. KOGAS has been under fire for its costly supply contracts signed when oil and gas prices were high, which has partly been blamed for its poor financial condition. KOGAS imported 31.41 million tons of LNG last year, down 13.5 percent from 2014, marking the second consecutive year of decline in LNG imports.

Tokyo Electric will start boosting Btu value of gas for retail sales

(Nikkei Asian Review; June 14) – Tokyo Electric Power will become a fully independent producer of city gas for households, putting the utility in a better position to compete in Japan’s deregulating energy market. TEPCO will install equipment at its Anegasaki power plant in Chiba Prefecture to boost the energy (Btu) value of natural gas, largely by mixing in small amounts of liquefied petroleum gas (such as propane), making the end product suitable for residential use that requires a richer gas than power plants.

TEPCO will spend roughly 5 billion yen ($47 million) on the project. Most of the gas that TEPCO currently sells to such large-volume users as factories is the untreated variety. For some gas that it supplies to gas distribution companies, TEPCO has been paying Tokyo Gas to modify the calorific values. TEPCO takes delivery of liquefied natural gas from multiple suppliers, stores it and then regasifies it for delivery or consumption to make electricity as needed.

With the new fuel-mixing facility, TEPCO plans to boost its sales by about 1 million metric tons of LNG per year by 2023. After the retail electricity market became fully liberalized this past April, TEPCO lost customers to Tokyo Gas and other new entrants. TEPCO seeks make up for the lost revenue by selling city (retail) gas when that market is liberalized next spring, including in package deals with electricity. TEPCO will be competing on the turf of Tokyo Gas, which serves over 10 million residential customers.

LNG producers look to build up downstream market to boost demand

(Reuters; June 12) – Energy giants such as Shell and Total are looking to build liquefied natural gas imports terminals and power plants in new markets to soak up the industry’s rapidly burgeoning supply. But gas demand growth is slowing, prices are down and the LNG volumes that companies are expected to produce will exceed those even major buyers such as China and Japan can absorb.

That has turned attention to the downstream market and opportunities to create new markets from Ivory Coast to remote Indonesian islands by building gas-fired power plants, pipelines, regasification and storage terminals. “We are ready to go downstream as much as it takes to unlock gas demand,” said Laurent Vivier, president for the gas division at Total. “We need to be present in downstream ourselves, to create demand and unlock bottlenecks … including regasification, pipelines and power plants.”

Total aims to triple the number of its gas and power markets. The company is taking part in LNG infrastructure tenders, including several gas-fired power plants, in countries including Indonesia, Chile, Ivory Coast, Ghana and Morocco, Vivier said. Shell believes the number of markets buying LNG could double, according to its chief financial officer, Simon Henry. “From around 20 to 30 … we can see potential for around 50 different markets if you look out to 2030,” Henry said.

India talks with Japan and Korea about LNG buyers’ alliance

(Reuters; June 14) – Energy-hungry India has restarted talks on a liquefied natural gas purchasing alliance with Japan and South Korea and may also include China as Asian demand for the fuel grows. “For the next two to three decades, gas is going to be a major part of the energy basket for Asian energy consumers,” Dharmendra Pradhan, India’s minister of petroleum and natural gas told reporters in Mumbai on June 14.

“We want to bring together the countries and form a network which can together source reasonable, rational and affordable LNG,” he said, adding that talks with Japan and South Korea have begun and China may also come onboard. State-owned GAIL India is a leader in the talks, which follow a similar attempt in 2013. Gas currently accounts for about 8 percent of India’s overall energy mix. In the past decade, while India’s domestic gas production has grown 10 percent, imports of LNG have risen 335 percent.

India’s gas demand stands at 4.236 billion cubic feet per day, whereas domestic supply is 2.824 bcf a day, making imports imperative, government data showed.

Gazprom says it is counting on strong growth in China’s gas demand

(Reuters; June 14) – Russia’s top gas producer expects China’s consumption to more than double, Gazprom Deputy CEO Alexander Medvedev said June 14, suggesting the company is still counting on robust growth in demand in China even as that nation’s economy slows. As part of Russia’s strategic shift eastward, prompted by rows with the West, Gazprom will supply China with gas via the yet-to-built Power of Siberia pipeline, raising volumes gradually to make China one of the biggest customers for Russian gas.

Gazprom still aims to start the pipeline in 2019. China has pledged to reduce its coal dependence, a major source of air pollution and greenhouse-gas emissions, and aims to double annual gas consumption to almost 13 trillion cubic feet between 2015 and 2020. However, sources close to Gazprom told Reuters in January that Russia is likely to scale back the volume of gas it plans to ship to China later this decade, due to the dive in global energy prices and uncertainty hanging over the Chinese economy.

Medvedev, however, sounded more optimistic. “Gas consumption (in China) will double and rise further,” Medvedev told reporters, without giving a timeframe. “Russian gas sees no rivals,” he said, when asked about competition in its markets from an expected influx of seaborne liquefied natural gas from the United States and other countries.

Low-cost LNG may allow utility in India to restart power plants

(Bloomberg; June 13) – India’s Essar Power is looking to buy imported liquefied natural gas for two power plants in the country’s western region now that a global glut of the fuel has cut prices by two-thirds since September 2014. The 515-megawatt Hazira facility and the 500-megawatt Bhander plant may resume operations within six months. The plants were shut down more than three years ago as imported LNG was priced too high for the company to afford.

The company is in discussions with suppliers including Shell and state-run GAIL India to supply the two plants in the western state of Gujarat, said Executive Vice Chairman Sushil Kumar Maroo. “The scenario is changing because LNG is becoming cheaper,” Maroo said June 10 in Mumbai. “Based on fundamental reasons, we feel LNG will remain affordable in the next five to eight years.”

Malaysia needs new contracts as older LNG customer deals expire

(Interfax Global Energy; June 13) – Malaysia’s gas production could jump by 25 percent over the next five years, but with gas losing market share to coal in the country, the challenge will be finding a use for it. Malaysia has significant gas potential, and it could see production rise by about 1.5 billion cubic feet per day between 2016 and 2020, Edi Saputra, a specialist in Southeast Asia gas and power at Wood Mackenzie, told Interfax Natural Gas Daily. That includes gas from probable developments.

But at the same time as production is growing, gas is starting to lose market share to lower-cost coal in terms of power generation in Malaysia. Wood Mackenzie estimates coal will increase its share of the fuel mix for power from 47 percent to 65 percent by 2020. However, the fall in global gas prices could change things, as lower natural gas prices will make the fuel more competitive, Graham Tyler, a Singapore-based senior director at consultancy Galway Group, told Interfax Natural Gas Daily.

Subbu Bettadapura, a Malaysian specialist with consultancy Frost & Sullivan, estimates the country’s gas consumption will rise slowly from 1.3 trillion cubic feet this year to almost 1.5 tcf in 2020. At the same time, Malaysia’s gas output will peak at 2.74 tcf in 2019. Malaysia has been a major exporter of liquefied natural gas since 1983. The country’s export contracts are gradually expiring and the national oil and gas company will need to negotiate new contracts to replace those expiring deals.

Egypt escapes fine for cutting deliveries to LNG plant

(Reuters; June 14) – The Paris-based International Court of Arbitration has ruled that Egypt’s state gas board EGAS will not have to pay a $270 million fine for cutting back feedstock gas deliveries at its foreign-ownership-controlled liquefied natural gas plant, the petroleum ministry said June 14. The Damietta LNG plant filed a complaint with the International Chamber of Commerce in 2013, alleging that its state partner had failed to comply with contracts by halting gas supplies in 2012 and not making payments.

The plant demanded EGAS pay $270 million plus interest for contracted but unused LNG plant capacity. The plant is 80 percent-owned by Union Fenosa Gas, a joint-venture between Spain’s Gas Natural and Italy’s Eni. The remaining 20 percent is split evenly between Egyptian state-owned companies. The plant opened in 2005. EGAS had committed to supplying about 700 million cubic feet per day, but in 2010 cut deliveries to 400 million cubic feet and then stopped all deliveries in 2012 as domestic turmoil and rising local demand reduced the volume of gas available for export.

TransCanada wins job for 500-mile line to bring U.S. gas to Mexico

(The Canadian Press; June 12) – TransCanada and a joint-venture partner have won a contract to build, own and operate a $2.1 (U.S.) billion natural gas pipeline to move additional gas into Mexico. The Calgary-based company said it will develop the 500-mile Sur de Texas-Tuxpan pipeline in cooperation with IEnova, a subsidiary of California-based Sempra Energy. TransCanada said it will invest about $1.3 billion in the partnership and will own 60 percent of the pipeline, with IEnova owning the rest.

Once completed in late 2018, the 42-inch-diameter pipeline will move 2.6 billion cubic feet of gas per day from pipeline connections at the southern end of Texas, underwater across the Gulf of Mexico to Tuxpan in Veracruz state. The investment increases TransCanada’s total assets and projects under development in Mexico to more than $5 billion, all covered by 25-year agreements with Mexico’s state-owned utility. TransCanada said that in the past eight months it has been awarded contracts to build two other gas pipelines in Mexico, both of which are already under construction.

TransCanada is ramping up its presence in Mexico as key projects closer to home face delays. The company is struggling with opposition to its Energy East pipeline to move Alberta oil sands production to eastern Canada for refineries and for export. And the company is slated to build numerous natural gas lines tied to proposed liquefied natural gas export terminals on Canada’s Pacific Coast, but final investment decisions on those LNG projects have been delayed by environmental and market concerns.

New U.S. gas pipelines run into eminent domain battles

(Penn Live; Harrisburg, PA; June 14) – In response to low oil and gas prices, drilling has slowed down across Pennsylvania, leaving empty rental homes in its wake and a host of businesses facing their own uncertain futures. But existing Marcellus Shale wells continue to produce huge amounts of natural gas. In many cases, energy companies that have for years been preoccupied with inking new leases and pulling more gas from the ground now are focusing on what to do with all the gas.

This is a large part of the reason for the energy industry’s push toward pipeline development, at the center of an increasingly heated public debate over property owner rights and the use of eminent domain in securing private land for “the public good.” In places like Lancaster County, PA, home to roughly 500,000 residents, landowners continue to oppose the planned Atlantic Sunrise pipeline, fearing the $3 billion, 10-county project’s impact on property values, quality of life and livelihoods.

Recognized public uses for the power of eminent domain have for decades included highways, roads, schools, public buildings, airports and pipelines. Only now, though, with domestic energy production shattering records and a staggering array of pipeline projects taking shape across the country, are eminent domain and pipeline battles becoming par for the course. Guidelines for formal residential challenges remain elusive and the results far from predictable, experts say.

North Dakota gas producers reduce flaring rate to 10 percent

(U.S. Energy Information Administration; June 13) – The volume of North Dakota’s gas production that is flared has fallen sharply since 2014. In March 2016, 10 percent of North Dakota’s total gas production was flared, less than one-third of the January 2014 flaring rate, which was 36 percent, according to the U.S. Energy Information Administration. The state in September 2015 established targets to reduce gas flaring.

Flaring rates and volumes have fallen while North Dakota’s production has continued to grow, setting a gas production record of 1.71 billion cubic feet per day in March 2016. Flaring (burning) gas produces carbon dioxide, a greenhouse gas. Natural gas flaring in the United States is not confined to North Dakota, but since 2012 the state has had the highest volumes of flared gas as its booming oil and gas production has exceeded the capacity of gas processing facilities and pipelines to move the fuel to markets.

Most North Dakota production is in the Bakken Shale, and as new infrastructure has been built more of the gas production has been brought to market. North Dakota regulations require that tax and royalties be paid for all gas flaring beyond a well’s first year of production, though exemptions are allowed. And the state can grant confidential reporting status to wells for the first six months of production. These wells, known as confidential wells, have nearly double the flaring rates of non-confidential wells.

Gas company will deliver LNG to northern Quebec diamond mine

(Press release; June 13) – Quebec’s Minister of Energy and Natural Resources Pierre Arcand and Gaz Metro CEO Sophie Brochu announced June 13 a major milestone in deploying the 2030 Energy Policy and the Northern Plan, with the start of liquefied natural gas deliveries to Northern Québec for the Stornoway Renard diamond mine. Located in the Otish Mountains, more than 640 miles from Montréal, it is the first Québec mining company that Gaz Métro will supply with LNG.

“With Gaz Métro LNG’s supply of natural gas, companies now have access to cleaner, higher-performance energy that offers substantial energy gains,” said Pierre Gabriel Côté, president and CEO of Investissement Québec. Through Investissement Québec, the government of Québec took a $50 million stake in the Gaz Métro subsidiary, Gaz Métro LNG, which is responsible for this project and for marketing liquefied natural gas. Investissement Québec’s mission is to foster the growth of investment in Québec.

In fall 2014, with the government of Québec and Investissement Québec, Gaz Métro announced a project to expand its Montréal liquefaction, storage and regasification plant to meet the needs of regions that are remote from the gas network, particularly Northern Québec, but also for the road and maritime transport fuel markets. Gaz Métro is the largest natural gas distribution company in Québec.

Cost-cutting pressures could erode skilled labor pool

(Interfax Global Energy; June 10) – With Australia’s large-scale energy projects all but shelved and its gas demand growth looking poor for the foreseeable future, financially constrained oil and gas operators are pushing contractors and suppliers to significantly cut costs. But with contractor margins already under 5 percent, some warn that further pressure on the service side of the business risks eroding skilled labor and could jeopardize the industry’s long-term future.

With the global liquefied natural gas market glut expected to continue well into the next decade, energy chiefs are becoming increasingly vocal about the need for suppliers to slash rates for project construction and labor, as well as for maintenance and operations. Wood Mackenzie data shows upstream capital costs have come down by at least 15 percent globally in the past year and that suppliers are being squeezed.

Geoffrey Cann at Deloitte said service providers have been under pressure for some time. On Australia’s East Coast, the operators of the three new LNG projects on Curtis Island have been putting pressure on their suppliers for price reductions for the past year. “I have seen letters from one operator to their suppliers demanding an immediate 10 percent rollback for calendar 2015 and expectations of a 30 percent further roll back in 2016,” Cann said. While this can certainly drive short-term efficiencies, the depth of cuts now being demanded could end up damaging the industry’s long-term, Cann said.

IEA says oil glut could ease later this year, maybe return next year

(Wall Street Journal; June 14) – Increasing Asian demand and worldwide disruptions to oil production could erase today’s oil glut by the end of 2016, the International Energy Agency said June 14. In its monthly report, the IEA said oil-production outages worldwide trimmed global supply by nearly 800,000 barrels a day in May, the first significant drop since early 2013. But the IEA warned that the surplus could reappear in the second half of next year if production resumptions exceed demand.

“Less oil has been stockpiled than we originally expected,” the report said, lowering its estimate of global oversupply in the first half of 2016 from 1.5 million barrels a day to around 800,000. That is due partially to production outages in Nigeria, where attackers have blown up oil installations in recent weeks, negating supply increases in other member states of the Organization of the Petroleum Exporting Countries.

The IEA said it also expects non-OPEC production to fall by 900,000 barrels a day this year from last year. The decline is due in part to wildfires that have devastated Canada’s oil sands. The agency said it expects global demand to grow next year by 1.3 million barrels a day to 97.4 million barrels a day. But even with higher demand, IEA said, oil production recovery in Canada, Nigeria or Libya could drive supply past demand and push prices down again.