Another step in the ongoing decarbonization of fossil fuels.

The Belridge oil field in the San Joaquin Valley of California has produced about 1.7 billion barrels of heavy crude since its discovery in 1911. Thanks to advances in solar power, its next 500 million barrels will be a little bit greener.

Here in the middle of the 22-mile long oilfield Aera Energy is set to spend an estimated $250 million to build California’s largest solar energy project. The centerpiece will be 630 acres of glass houses, like greenhouses on farms. Hung inside the glass boxes will be solar collectors — basically flimsy mirrors made from sheets of aluminum foil and suspended by wires. As the sun moves across the sky, small motors pull the wires to adjust the mirrors’ pitch. The reflected rays are concentrated on a network of pipes carrying water throughout the glass block, creating steam. The plan at Belridge is to use the sun’s power to make 12 million barrels of steam per year.

What’s the steam for? Well Belridge is what you’d call a geriatric oil field. Its oil no longer flows under its own natural pressure, so its operator, Aera Energy, is continuously injecting steam into the reservoir rock in order to loosen up and coax out more oil. The so-called steam floods have been going on so long at old fields throughout the region around Bakersfield, Calif., that oftentimes more than 95% of the fluid that comes out of the ground is water. After the oil is skimmed off, the water is repressurized and injected right back down into the reservoir.Production at Belridge peaked at 160,000 barrels per day in 1986, and today it is still doing 76,000 bpd — a rate that Christina Sistrunk, CEO of Aera Energy, thinks it can keep up for the next 20 years. That long life expectancy is why is makes economic sense for Aera to invest an estimated $250 million with GlassPoint to build its solar technology.

With solar, you make your big investments upfront, then effectively get your fuel for free when the sun shines. Otherwise, when burning natural gas, Aera faces continual fuel bills, and gets dinged by California regulators for its industrial carbon emissions. The Glasspoint installation will eliminate 375,000 tons of carbon emissions each year, and offset about 4.9 billion cubic feet of natural gas use. At about $3 per thousand cubic feet, that works out to about $15 million in gas savings per year for fuel. Carbon credits are trickier to figure. Recent auction prices under the California-Canada carbon cap-and-trade program have come in at around $14.50 per ton. Outyear estimates are higher. Belridge carbon reductions might then be worth roughly $5 million per year? Aera’s Sistrunk won’t comment on such speculations. What she will say is that even with cap-and-trade and the natural gas savings, and other state and federal incentives, this solar project “is not overwhelmingly economically robust.”

So why go to the trouble? Because it looks good to do solar projects. And because California, despite being the epitome of America’s car culture, has made it an ever harder place for oil companies to maintain a “social license” to operate. “It’s a challenge in California, where you need your performance to be even stronger to offset the regulatory costs of doing business here,” says Sistrunk. “Previously we couldn’t afford to do it.”

Six years ago Glasspoint built its first glass houses for Berry Petroleum at another Kern County oilfield. That caught the eye of the Gulf sultanate of Oman, leading to a $600 million contract to build a 1,000 mw system to support steam-flooded oil production there. It’s surprising, but “natural gas in the Middle East is not evenly distributed,” says GlassPoint CEO Ben Bierman. Qatar and Iran have a lot of gas, while Oman, Kuwait and Saudi Arabia are relatively short. As a result, planning for big capital projects in the region assume long-term gas at $5.50 to $7 per mmBTU. That’s double the prevailing price at Henry Hub in Louisiana.

What’s exciting about the Aera Energy deal for GlassPoint is that it gives them an implicit seal of approval from ExxonMobil and Shell, which signed off on their JV’s investment. Bierman claims that scaling up its business to supply the Oman project (operated by Shell) has enabled Glasspoint to reduce its costs by 55%. Bierman says their objective is to make the system as simple and foolproof as possible by tapping into supply chains that serve the much-larger agricultural market. He predicts big growth ahead in markets that are already ramping up big steam floods like Bahrain, Kuwait and especially Saudi Arabia. Further out he has his eye on Indonesia and China. There’s no supply bottleneck in the way of growing to eight times their current size, says Bierman, who now lives in Oman. “The stars finally aligned.” Thanks to the oil business, in a decade GlassPoint could be among the biggest solar companies in the world.

Venezuelan crude exports to the U.S. fell last month to their lowest levels since January 2003, according to new Reuters data.

Sanctions and low production caused the decline in November. The last time levels were this low, an industry strike had shut down a large portion of the Latin American nation’s oil sector.

State-run PDVSA sent a total of 475,165 barrels of oil the U.S. per day in November – a 36 percent drop from last year and a 12 percent drop from the previous month.

The last four years have seen the country lose one million bpd of production, mostly due to inadequate funds to maintain oil facilities, according to the OPEC. Three years of low oil prices have made it difficult for state revenues to meet national budget demands.

The output and revenue decline is causing Caracas to take oil from its joint ventures in the Orinoco Belt to keep the lights on. Hamaca crude from a joint venture with Chevron is increasingly being used for domestic refining instead of being exported to the U.S.

At the end of August, the U.S. stepped up its sanctions on Venezuela, prohibiting dealings in new debt or equity issued by PDVSA or the government. President Nicolas Maduro claims that the string of U.S. sanctions imposed this year on Venezuela amount to “financial persecution”.

In a surprise move at the end of last month, Maduro named a National Guard major general as the new head of PDVSA and the country’s oil ministry— Manuel Quevedo— who vowed to end corruption at PDVSA, but didn’t mention how he would approach the company’s huge foreign debt.

Analysts and bond investors will be closely following Quevedo’s statements and moves to try to figure out if the new chief will continue Maduro’s policy to try to service debt at all costs—even if payments are late—despite cash reserves quickly running out.

The world’s liquefied natural gas (LNG) market has dramatically changed over the past few years. Continuously growing supply has led to a glut, and the U.S. starting LNG exports has led to more flexible contract terms. LNG trade is increasingly shifting to a buyers’ market, where importers are shaping the future of the LNG trade deals with exporters.

Charif Souki, co-founder of the U.S. firm that upended LNG trade contracts, Cheniere Energy, has started a new company after being ousted from Cheniere two years ago. Now Souki’s new venture, Tellurian Inc, is talking with potential buyers who want to be not only importers but equity investors as well.

“Nobody is keen to sign contracts,” Souki told Bloomberg, “Even the people who kind of think they should are afraid to do it.”

“We’ve been approached by at least a dozen and a half people, companies, that say: ‘We’d like to participate with you. You know how to build facilities cheaply and we’ll trust you to go and find the resource,’” Souki said, recounting what buyers are telling him about potential deals.Tellurian plans to build the Driftwood LNG export facility near Lake Charles, Louisiana—with plans to export 26 million tons of LNG per year. The company expects to begin construction of Driftwood LNG in 2018, deliver first LNG in 2022, and ramp up the facility to full operations in 2025.

At the end of last year, France’s oil and gas supermajor Total SA signed a deal to buy a 23-percent stake in Tellurian for $207 million to develop an integrated gas project, from the acquisition of competitive gas production in the U.S. to the delivery of LNG to international markets from the Driftwood LNG terminal.

Last month, Tellurian signed a deal to buy natural gas producing assets and undeveloped acreage in northern Louisiana for $85.1 million, as part of its strategy to add production assets to grow its business.

“We expect our full cycle cost of production and transport to markets will be approximately $2.25 per MMBtu, which represents a significant savings to natural gas we will purchase at Henry Hub and other regional liquidity points,” Tellurian president and CEO Meg Gentle said.

Now potential LNG buyers want partnerships, not just supply deals, according to Souki, and to executives at other U.S.-based LNG developers who spoke to Bloomberg.

“Today, it’s the buyers’ market,” Leonid Mikhelson, CEO at Russia’s gas firm Novatek, recently told reporters, in a sign that LNG exporters around the world see that importers are dictating the market terms.

Last week, India’s Minister of Petroleum and Natural Gas, Dharmendra Pradhan, tweeted “As we increase the % of gas in our energy basket as cleaner fuel we need better terms & prices for our LNG import contracts.”

According to the International Energy Agency’s (IEA) Global Gas Security Review 2017, “Looking forward, the pool of legacy export contracts with fixed destination and long duration can be expected to shrink as these expire, and would be replaced by more flexible contracts.”

Last year, the share of flexible destination contracts continued to increase and made up 41.9 percent of newly signed volumes in 2016, the IEA’s review said. In addition, the average contract length has declined. For contracts signed before 2014, the average duration was 16 years, for deals in 2015 it was 10 years, and for contracts signed in 2016, the average duration was just 9 years.

“In fact, a greater proportion of new contracts have flexible terms (i.e. no destination clauses), encouraged by both the innovative business models of the US suppliers and policies in the consuming countries and territories. Expiring ‘legacy’ long-term contracts would also provide an opportunity to renegotiate terms towards more flexibility,” the IEA said.

At the beginning of this year, James Walker, a specialist with Energy Insights at McKinsey, wrote:

“‘Short-termism’ is growing in the LNG market, which is increasingly characterized by greater spot availability, shorter term supply contracts and buyers diversifying their portfolios to capitalize on the current market oversupply.”

McKinsey expects the LNG market to continue to be oversupplied through 2024, but China having “great potential to absorb a large share of the surplus volumes from 2018 onwards.”

In the current state of the LNG market, it’s now a buyers’ world.