(Adds latest prices) Jan 4 (Reuters) - U.S. natural gas futures jumped about 5% on Wednesday from a 10-month low in the prior session on forecasts for higher-than-expected demand for liquefied natural gas (LNG) exports over the next two weeks. Traders said the biggest uncertainty for the market remains when Freeport LNG will restart its LNG export plant in Texas. After several delays from October to November and then to December, Freeport expects the facility to return in the second half of January, pending regulatory approvals. That is in line with what many analysts have long been saying - that Freeport would likely return during the first quarter of 2023 because the company still has a lot of work to do to satisfy federal regulators before restarting the plant. Whenever Freeport returns, U.S. demand for gas will jump. The plant can turn about 2.1 bcfd of gas into LNG, which is about 2% of U.S. daily production. Freeport shut on June 8 after a pipe failure caused an explosion due to inadequate operating and testing procedures, and human error and fatigue, according to a report by consultants hired to review the incident and suggest corrective actions. Several vessels, including Prism Diversity, Prism Courage, Prism Agility and Elisa Larus, have been waiting in the Gulf of Mexico to pick up LNG from Freeport, some since early November. Other ships were sailing toward the plant, including Corcovado LNG, which is expected to arrive in mid-January, and Kmarin Diamond and Wilforce expected in late January. In other LNG news, the Cadiz Knutsen was expected to arrive at Constellation Energy Corp's Everett LNG terminal in Massachusetts in a few days with a third cargo of the super-cooled fuel from Trinidad this winter. Cadiz Knutsen also delivered LNG to Everett in November and December. But with Everett competing with European buyers willing to pay around $20 per million British thermal units (mmBtu) for gas versus just $4 in the United States, the Massachusetts port imported just 19.7 billion cubic feet (bcf) of gas as LNG in 2022, according to Refinitiv data. That is down from 21.4 bcf in 2021 and a five-year (2017-2021) average of 40.2 bcf, according to federal energy data. New England depends on LNG and oil to fuel some power plants on the coldest days when most of the region's pipeline gas is used to heat homes and businesses. About half of the power generated in New England comes from gas-fired plants. Front-month gas futures for February delivery rose 18.4 cents, or 4.6%, to settle at $4.172 per mmBtu. On Tuesday, the contract dropped about 11% to settle at its lowest since Feb. 11. Despite Wednesday's price jump, the front-month remained in technically oversold territory with a relative strength index (RSI) below 30 for a fifth day in a row for the first time since October. Data provider Refinitiv said average gas output in the U.S. Lower 48 states rose to 98.3 bcfd so far in January, up from 96.7 bcfd in December but still below the monthly record of 99.9 bcfd in November 2022. Even though the weather is expected to remain warmer-than-normal through mid-January, Refinitiv projected average U.S. gas demand, including exports, would jump from 110.5 bcfd this week to 121.5 bcfd next week as LNG export rise and temperatures ease ahead of what are usually the coldest weeks of the year. Those demand forecasts were higher than Refinitiv's outlook on Tuesday. U.S. LNG exports were expected to rise from an average of 10.7 bcfd last week to 11.8 bcfd this week and 12.4 bcfd next week as units at Cheniere Energy Inc's Sabine Pass and Venture Global LNG's Calcasieu in Louisiana boost output. Week ended Week ended Year ago Five-year Dec 30 Dec 23 Dec 30 average (Forecast) (Actual) Dec 30 U.S. weekly natgas storage change (bcf): -228 -213 -46 -98 U.S. total natgas in storage (bcf): 2,884 3,112 3,199 3,099 U.S. total storage versus 5-year average -6.9 -2.7% Global Gas Benchmark Futures ($ per mmBtu) Current Day Prior Day This Month Prior Year Five Year Last Year Average Average 2022 (2018-2022) Henry Hub 4.01 3.99 4.26 6.54 3.60 Title Transfer Facility (TTF) 21.60 22.42 28.25 40.50 14.39 Japan Korea Marker (JKM) 29.35 29.52 28.53 34.11 14.31 Refinitiv Heating (HDD), Cooling (CDD) and Total (TDD) Degree Days Two-Week Total Forecast Current Day Prior Day Prior Year 10-Year 30-Year Norm Norm U.S. GFS HDDs 335 342 472 440 444 U.S. GFS CDDs 3 3 4 4 3 U.S. GFS TDDs 338 345 476 444 447 Refinitiv U.S. Weekly GFS Supply and Demand Forecasts Prior Week Current Week Next Week This Week Five-Year Last Year Average For Month U.S. Supply (bcfd) U.S. Lower 48 Dry Production 87.0 98.6 98.6 94.0 88.8 U.S. Imports from Canada 10.1 7.9 9.3 9.2 9.4 U.S. LNG Imports 0.0 0.0 0.0 0.1 0.4 Total U.S. Supply 97.0 106.5 107.8 103.3 98.6 U.S. Demand (bcfd) U.S. Exports to Canada 1.5 3.3 3.3 2.5 2.8 U.S. Exports to Mexico 5.0 4.8 5.1 5.5 5.3 U.S. LNG Exports 10.7 11.8 12.4 12.0 7.2 U.S. Commercial 20.7 12.5 15.0 19.3 17.1 U.S. Residential 36.0 19.8 24.4 33.1 29.8 U.S. Power Plant 33.8 27.2 29.0 30.5 28.5 U.S. Industrial 26.8 23.7 24.7 26.2 25.6 U.S. Plant Fuel 4.3 4.9 4.9 4.9 4.9 U.S. Pipe Distribution 3.3 2.4 2.7 2.4 2.4 U.S. Vehicle Fuel 0.1 0.1 0.1 0.1 0.1 Total U.S. Consumption 125.0 90.6 100.7 116.5 108.4 Total U.S. Demand 142.1 110.5 121.5 136.5 123.7 U.S. weekly power generation percent by fuel - EIA Week ended Week ended Week ended Week ended Week ended Jan 6 Dec 30 Dec 23 Dec 16 Dec 9 Wind 13 11 9 12 9 Solar 2 2 2 2 2 Hydro 7 6 6 6 6 Other 2 2 2 2 2 Petroleum 0 1 0 0 0 Natural Gas 34 35 37 37 39 Coal 19 23 24 20 20 Nuclear 24 19 19 20 21 SNL U.S. Natural Gas Next-Day Prices ($ per mmBtu) Hub Current Day Prior Day Henry Hub 3.64 3.52 Transco Z6 New York 2.65 2.68 PG&E Citygate 23.36 16.54 Dominion South 2.27 2.27 Chicago Citygate 3.34 3.38 Algonquin Citygate 2.85 2.94 SoCal Citygate 26.18 18.57 Waha Hub 2.40 2.25 AECO 2.98 3.25 SNL U.S. Power Next-Day Prices ($ per megawatt-hour) Hub Current Day Prior Day New England 43.47 38.25 PJM West 38.75 32.25 Ercot North 25.75 15.00 Mid C 56.00 165.00 Palo Verde 212.75 116.00 SP-5 225.00 121.25 (Reporting by Scott DiSavino; Editing by Chizu Nomiyama and Josie Kao)