[NGW Magazine] Upstream Minnows Seek Investors
When it comes to catching minnows, sellers' and buyers' expectations on oil prices had come into fairly close alignment this year. There is no shortage of stocks for the adventurous investor, and there is a wide range of plays depending on risk appetite.
Today's high oil prices have rescued some of the small to medium cap producers, less able to survive the lean times than the diversified and well-resourced and financed international oil companies.
But location is also important, as reserves in countries with predictable fiscal terms also provide some useful comfort for gas, which has enough other problems to wrestle with. So there are many trillions of cubic feet of resources in the hands of private equity funds, many of which believe they can find a way to bring their assets to market and exit after five or ten years. As the joke has it, a long-term investment is a short-term investment that has gone wrong.
Addressing the 121 oil and gas investment conference in Hong Kong May 2, New Zealand-focused onshore-focused TAG Oil boasted a breakeven price of $34/bbl Brent crude, including all the general and administration costs. The fact that gas prices are trending higher in New Zealand also helped, said CEO Toby Pierce. Its licences are also all onshore, and therefore unaffected by the government's plan to stop issuing new offshore licences, which showed how even OECD countries have the capacity to shock investors.
TAG is planning to step out into the Surat Basin, a 'Permian' oil play in Australia, but not to change its policy of high working interests and operatorship of all assets, to maintain operational and financial flexibility.
Other companies for whom the location of reserves is critical for different reasons are Australia-listed Real Energy and Calima Energy. For the former, having production close to Santos' gas processing facilities and pipelines is an important part of its Australian Cooper Basin projects, where it has drilled three wells in Tamarama.
The play extends a long way laterally and has “massive certified resources” of some 13 trillion ft³ and Real hopes to produce between 40% and 45% of it.
Being close also to Australia's east coast is also beneficial to the project's economics, as gas prices there have been high, around A$8-12/GJ, CEO Scott Brown told NGW. It can deliver the gas to Sydney, Adelaide, Brisbane, or to Gladstone for liquefaction, although its intention is to deliver the gas to a utility or another domestic gas buyer. It has signed a memorandum of understanding with Weston Energy for up to 10 terajoules/day (97.5mn m³/yr), at a fixed price that is not linked to oil, he said: “That is easier, from our perspective. We can get a spot contract but the market is less sophisticated than North America’s.” And once the capital investments are done, the operating expense is low, he said.
The company could drill six more wells in order to produce 20 terajoules/day (about 20mn ft³/d) of gas and move later to full field development. The carbon dioxide is removed at the Santos plant and there is also some condensate in the well, which goes “effectively at the oil price.” Santos at that point was considering a takeover offer by oil and gas producer Harbour Energy, he said, which as a private-equity backed firm will seek to sweat its assets harder.
Oil price raises hopes
Harbour’s backers include Swiss trading house Mercuria, which wanted to take a material equity stake, put at about 10%, in the proposed Santos deal whose total value is put at some $10.3bn (A$13.7bn).
The original bid represented a 28% premium to the closing share price before the announcement, reflecting Mercuria’s keenness to get into LNG. One analyst described it as a knock-out bid; others said the oil market remained in backwardation and said they doubted the board would be wise to refuse. Indeed, the boss of BP Bob Dudley told Reuters May 18 he still sees the Brent crude oil price in the long term at $50-$65/bbl.
Harbour raised its bid after the Brent crude price rose above $80/bbl, from $4.98/share to $5.21/share, possibly to deter other bidders, but it was still not enough and Santos surprised the market by turning it down. “Since receipt of the indicative proposal, Brent oil prices have increased by 14% and the share prices of other major ASX-listed energy peers by an average of 18%. The Santos business has continued to perform well and is generating strong cash flow,” the company said, explaining its decision.
Another private-equity backed company with production is Canada's Vermilion Energy: it farmed into acreage with Nafta in Slovakia. Like Real, it is not interested in trading there but selling to a local aggregator.
Similarly in the Netherlands Vermilion sells its gas to a local utility, not at a fixed price but indexed to the Dutch Title Transfer Facility, as is its German gas output. And in Hungary, it is partnered with MOL: this winter it drilled its first exploration well that tested 5.8mn ft³/d gross. It hopes to bring it on to production in mid-summer and the gas will need processing by MOL.
It is looking at volume growth of between 5% and 7%/year and it has enough of a project pipeline to keep it going for another seven or eight years, its investor relations head Kyle Preston told NGW. It has been investing in small bites of $100mn or less, funded internally: “we have never had problems accessing capital,” he said.
Its biggest acquisition, the conventional oil and associated gas producer Spartan Energy in Canada, was C$1.4bn, realised mostly through a share swap and also the assumption of C$175mn of debt. The attraction was low decline rates, and high netbacks, Preston said; and it was cheap. “Oil and gas companies were out of favour, and low to mid-cap companies were heavily discounted. This was a good opportunity for us,” he said. It bought “opportunistically” at the equivalent of just 4.5 times cash flow, and it was “highly accretive for us.”
It is not interested in the UK North Sea but it has 18.5% of Corrib in the Atlantic Ocean, offshore northwest Ireland; it is taking over the operatorship from Shell along with another 1.5%, to give it 20%, a deal expected to close in the middle of June, he said. Canada Pension Plan Investment Board is to take over from Shell as Corrib’s largest equity partner, although Equinor (formerly Statoil) retains a 36.5% interest.
The Corrib field remained at plateau until late last year. Gross output is 350mn ft³ but 15% annual decline is now expected from this year onwards. It is sold at a discount to the UK NBP to reflect the subsea transport cost to Moffat (southwest Scotland) but has a guaranteed market in Ireland.
Calima Energy has assets in the Montney Basin, in western Canada, a siltstone rather than shale province, which it believes are profitable even at today's low prices. It farmed into acreage very cheaply early on – paying a fraction of the market value today – and it is expecting strong production, based on seismic analysis and actual results from the analogous and adjacent Saguaro Resources acreage which is "doing very well," according to Calima's CEO Alan Stein – who had earlier set up Ophir Energy, now sitting on over 20 trillion ft³ offshore Tanzania and Equatorial Guinea, and ran it until 2011.
His successor at Ophir, Nick Cooper, stepped down after a successful seven-year run May 18 after failing to clinch financing for its potentially transformative Fortuna LNG project offshore Equatorial Guinea. Stein went on to set up Havoc Partners which in turn sold assets to Calima.
Freeing Canadian gas
"Calima got in early at a competitive price," he said. About a quarter of the output in energy terms is liquids: that drives the project, and future sales of acreage will provide more revenue. Being where it is, the gas needs a higher price to be profitable, as there is not enough demand nearby. The AECO hub [in Alberta] has even seen negative lately.”
However, taking the gas further afield would create value for it, he told NGW. At the moment it is a by-product of condensates. Taking it to Canada’s northeast coast for liquefaction, or to the west coast, could also work, theoretically.
A few companies have shelved their British Columbia liquefaction plans lately, but Shell's LNG Canada has just awarded an EPC contract and could take a final investment decision in early winter.
Chevron is also working on a project that could take off too, he said. There are also two liquefaction projects planned for northeast Canada: Pieridae’s Goldboro project and Bear Head LNG’s project in Point Tupper, both in Nova Scotia, but no FID has been taken in either case, leaving the gas where it is for now. "The dynamics of the gas market are constrained by infrastructure," Stein said.
Pieridae wants to build a 10mn mt/yr export project; it signed a 5mn mt/yr contract inked with Uniper in 2013, still in place, and in early May 2018 agreed a further 1mn mt/yr deal with an unnamed European utility – both being for ten years.
US oil also faces infrastructure challenges: given the lack of export capacity there is a chance for the West Texas Intermediate discount to Brent to grow further if, as Dudley expects, US crude producers ramp up output and cap prices. As of May 21 it was $7.20/bbl cheaper.
Other companies rely heavily on hiring relevant expertise: Canada's Renaissance is focused on Mexican oil and gas, and has assembled a four-strong team of Mitchell Energy that "cracked the code" of the Barnett shale gas, triggering what was to become the shale revolution. Its eye is on the shale oil production in the Tampico-Misantla basin, for which it announced March 5 a C$11mn (US$8.6mn) private placement.
William Powell