North America's oil and gas sector suffered in 2016, but survived its trial of strength
Canada's oil sands projects. The uptick in prices in the second half of 2016 tested their ability to bounce back. The first Lower 48 liquefied natural gas plant started shipping and the US lifted oil-export restrictions, scoping out global markets' appetite for American energy. Corporate deal-making picked up.
In 2016, the industry showed remarkable flexibility; it was quick to take drastic, and often painful, action to survive. Budgets were down by around 80% in 2016, from 2014. Companies sacked tens of thousands of workers and drilled about a third of the wells they drilled during the boom.
They harried services firms into lower rates and squeezed more oil and gas out of each well. In 2014, many said $60-70 a barrel would keep them in the money. In 2016, it was $50-60/b.
America's robust capital markets came to the rescue. Bond markets were mostly closed to the industry, as companies' credit ratings were repeatedly cut. But banks largely stood by shale drillers and kept lending. Equity markets were also important, allowing shale firms to raise more than $20bn over the course of the year to mend balance sheets and fund takeovers. Overall, companies outspent their cash flow by around 20%.
But there was plenty of red ink. For around 60 companies, bankruptcy was the only option, and few producers were profitable in 2016. US oil output slipped. In the Lower 48, it fell by around 0.9m barrels a day - 13% - to 6.2m b/d in the fourth quarter.
But swift cuts were matched by swift recovery - in the Permian shale at least. While the Eagle Ford and Bakken continued to struggle, even as prices ticked above $50 in the second half of 2016, the Permian saw a frenzy of deal-making; its rig count rose too, and output stabilised. In 2016, it became clear that the Permian is America's premium play. Canada's oil sands faced tests of their own. The biggest blow came from a wildfire that raged in northern Alberta in the spring, at one stage knocking out more than 1m b/d of production. Canada's average crude output for 2016 will be roughly flat compared with 2015, at around 4.5m b/d. But new capacity came online at existing projects. Cenovus added 80,000 b/d at Christina Lake and Foster Creek. ConocoPhillips expanded its Surmont mine. Canadian Natural Resources added 45,000 b/d at Horizon.
Sackings, wage deflation and the hit to Alberta's economy were all quite severe, but the relentless focus on cutting costs seemed to work.
Imperial Oil's unit costs were down by 35% from 2014 to less than $30/b. Suncor, the largest oil-sands producer, saw cash-operating costs fall to about $20/b. Others reported similar savings. But growth plans have largely been shelved.
Producers also feared that Alberta's new 100m-tonne-a-year cap on carbon emissions from the oil sands would stop new plants being built. The federal government, meanwhile, proposed a national carbon tax that would cost $50 by 2022 - an added expense for economically troubled projects.
Canada made scant progress finding new routes to export from the oil sands, as opponents dug in for a long fight. Kinder Morgan's TranMountain proposal to the west coast and TransCanada's Energy East emerged as the favourites for approval.
The US had no such trouble finding outlets to global markets, as the first Lower-48 LNG projects and the lifting of the crude-export ban made 2016 a landmark year for American energy exports. Although crude exports were roughly flat at nearly 0.5m b/d in 2016, compared with 2015 (when nearly all exports went to Canada), American oil found its way for the first time to new markets in the Caribbean, Latin America, Europe and Asia.
The tumultuous year also brought some deal-making - and some spectacular deal failures. The Permian was the world's hot-test upstream market for mergers and acquisitions, with more than $10bn in deals over 2016. The frenzy sent acreage valuations to record highs for US shale, even as oil prices languished.
The biggest M&A headline of the year was Halliburton's failed $35bn takeover of Baker Hughes. Schlumberger, by contrast, successfully bolstered its deep-water prowess with its $14.8bn acquisition of Cameron International.
The midstream also saw some missteps, as well as ambitious marriages, as players sought to tackle the downturn through mergers. Pipeline operator Energy Transfer Partners backed out of its $37bn deal to buy rival Williams Company in June. But Enbridge's $28bn deal to buy Spectra Energy looked more likely to succeed.
This article is part of Outlook 2017, our annual book looking at energy market trends for the year ahead. To purchase a copy, click here