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    UK E&P heads for net zero [NGW Magazine]


The buzzword for UK industry is net zero carbon: the only official question mark is over the achievable deadline. [NGW Magazine Volume 4, Issue 19]

by: William Powell

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NGW News Alert, Top Stories, Europe, Premium, NGW Magazine Articles, Volume 4, Issue 19, Energy Transition, Political, United Kingdom

UK E&P heads for net zero [NGW Magazine]

Upstream industry group Oil & Gas UK (OGUK) will do what it can to help the UK achieve its legal obligations on climate change, it said September 4 as it released its Economic Report 2019. To the policy objective of maximising the economic recovery of the UK continental shelf's oil and gas resources, which was set earlier this decade, has been added the government's nationally binding goal of net zero carbon emissions by 2050. The two are not incompatible, it says, with at least half of the UK's oil and gas demand potentially being produced at home by that date – and with the blessing of the independent Committee on Climate Change, too.

OGUK's Roadmap to 2035: a Blueprint for Net Zero addresses the new goal in some detail. It is a central part of its Economic Report 2019, which painted a patchily encouraging picture of oil and gas output.

OGUK CEO Deirdre Michie said: “Our Economic Report 2019 shows a greater proportion of UK demand being met from domestic production, exploration and drilling activity on the increase and a continued pipeline of new projects emerging. We need to build on this investment to encourage new fields to be developed to replace those coming to the end of their life. This will ensure as much as possible of UK demand is met from our own resources.”

Oil and gas from all sources met 75% of the UK energy needs last year, and UK production met 45% of that; and it provided 51% of UK gas needs and 67% of UK oil needs. It saved £20bn on imports, contributed $24bn to gross domestic product and provided work for 270,000 employees. It also generated a lot of free cashflow which the government is keen to see reinvested at home, not spent abroad in lower-cost basins.

Of the gas imports, 72% were directly from Norway and 15% from global LNG suppliers. The other 13% was pipeline gas from Belgium and Netherlands, which would be a mix of all sources including Norway and regasified LNG.

Oil production fared better than gas last year, as the oil price has been higher on an energy-equivalent basis, and the returns better than for gas. This year output will rise again, by 2% or 3%; but that is mostly owing to the Clair Ridge oilfield.  Gas prices at the trading hub (NBP) have plunged this year, with day-ahead prices hitting 23 pence/therm, a 15-year low, in June; and the average month-ahead price is down 50% since January. There have been some major gas finds too and more project sanctions are expected this year, the latest of which was Shell’s Pierce field. The low rate of approvals in 2016-2017 will mean lower output until the early 2020s, but OGUK sees a healthy pipeline of projects. Last year, 13 were approved, which was more than in the previous three years combined; and while this year started slow, OGUK expects ten by the year end, representing £2bn of investment.

Representing Neptune Energy, the privately-backed producer with a gas focus that was founded four years ago, Daryl Jones told a briefing in London that the company would not change its direction owing to lower gas prices, relative to oil. “We take the long-term view,” he said. Projects had though to pass muster, economically

Generally, he said that the world of net zero carbon had room for an industry that not only created economic growth but also represented security of energy supply. Neptune exists, he said, because the shareholders saw the potential for significant UK continental shelf production for decades to come. One of the bigger gasfields, Cygnus, which Neptune operates, has been running for two years and has another 18 years’ life, he said.

And being relatively small, it can quickly assimilate new technology, unlike the much bigger players that are now pulling out. “Technological barriers are falling and this works against the slower-moving companies,” he said. As an example, he said Neptune operated a wholly electric platform in Dutch waters, eliminating gas turbines that account for two thirds of the offshore industry’s direct emissions. Neptune has also invested in German onshore gas, developing production assets that came with the acquisition of part of French Engie.

But there was no room for complacency: in Norway, a country with a state involvement in every asset, capital expenditure was $95bn from 2014-18, compared with under $65bn in the UK.

He said the UK was very innovative and responded well to difficulties, but it needed to remain so when oil prices were high.

Petrofac’s strategy head Jonathan Carpenter agreed, repeating the line – much used four years ago when the oil price crashed – that one should “never waste a crisis.” Operators must not revert to type as prices rise, but continue the collaboration and the application of technology and find new ways of working. However, he said he could see the green shoots of recovery, as drilling activity was up, operating costs were down and productivity per person was also up. But costs needed to fall further, and maintenance time had to be shortened. To have plant working on average three days out of four might be an improvement on past practice, but there is still a lot to do, he said. The application of technology, both digital and mechanical, would be important parts of this.

Proprietary or licensed technology that it can in theory use on platforms where it has a contractual role of some sort includes Petrolytics; digital twins; and Connected Worker. The first, taking data readings such as temperature and vibration aberrations from all over a plant allows the operator to anticipate the need for a replacement part weeks ahead of time, meaning less lost time and money. The company is aiming to achieve 90% of the maximum operating time compared with 75% average today. Connected worker technology shortens communication time offshore.


BOX: Zennor comfortable with markets

Private equity-backed explorer Zennor Petroleum is looking forward to rising output from its mix of assets that will take it from 5,000 barrels of oil equivalent/day (boe/d) to 35,000 boe/d net output in the next five years or so. Getting there will not mean any additional financing deals, CEO Martin Rowe told NGW early in October, as it still has a $100mn available to it from a  financing agreement with private equity investor Kerogen, as well as cashflow from operations; and a loan that was related to work on its Finlaggan field.

Zennor entered the North Sea in 2015 when it bought First Oil, when the oil price was around $30/barrel. So the margins on production today are “very robust” at prices down to that level. Also the geopolitical risk is low, he said. In those days, there were a lot of “unloved” assets and the North Sea was “underpopulated” and there is room even for more players with that approach. He quoted approvingly the CEO of Chrysaor’s substantial spending plans for J-Block and Britannia, which will deliver a significant amount of barrels. Its CEO Phil Kirk told Reuters in September, when the acquisition closed, that Chrysaor plans to spend $800mn-$1bn/year on its portfolio in the coming years. “And that is a good thing,” Rowe said. Even Chrysaor, which bought the assets from Shell, which acquired them as part of BG, cannot do everything and more ‘people like us’ are needed, he explained.

Many companies such as Delek-owned Ithaca, which bought US Chevron’s portfolio, have declining profiles. “Not many are doing new projects,” he said, apart from some high-profile exceptions, such as Siccar Point.

Zennor has not been ambitious on the trading side, buying put options for its Britannia and Eastern Trough Area Project (Etap) output or selling equity output on a ‘vanilla’ basis at the beach. This provides cashflow for development work.

Britannia and the BP-operated Etap are where Zennor’s attention is focused. He says the majors, while disposing of some assets, are determined to keep others going, as hubs. Etap is a case in point, analogous to Shearwater for the Anglo-Dutch major Shell.

Rowe is also happy that the operatorship of Britannia passed from ConocoPhillips to Chrysaor September 30, as Chrysaor and Zennor have similar strategies and can see that plenty of exploration work remains to be done to get the most value from the area and the platform itself. Gas goes to the Sage terminal in Scotland and the condensate through the Forties Pipeline System.

But when volumes mount from its 100%-owned Finlaggan field in a few years, he said that the company would look at a tender process for the 100mn ft³/day of gas it will produce. The reservoir has higher pressure than Zennor had expected – “it’s good-quality rocks,” he said – and the company drilled two wells, which are tied back to Britannia, for which some platform modifications were needed. Finlaggan will be nominally 85% complete by the end of the year and the tie in will be done at the next triennial Britannia maintenance.

The gas and condensate at Finlaggan are the same as Britannia, and are about three-quarters gas. Rowe says he is comfortable with that too, the future being gassier as the energy transition continues. But except for key issues such as health and safety, Zennor is not going above and beyond the call of duty: content with its position “under the radar,” it does not have ambitious plans to decarbonise its offshore power generation, for example. Saying that Zennor supports Oil & Gas UK’ 2035 roadmap is as far as he will go.

Zennor has been somewhat innovative elsewhere though, regarding oilfield services. First, he leaves it to the contractors to choose the equipment, as long as it meets the functional specification. And second, as long as deadlines are met, the contractor can fit in the work around other projects, and this flexibility is reflected in the price, he said. “There are lots of ways to skin a cat,” and he does not dictate each step of the process.

After Finlaggan, Rowe will be lining up “the next slew of projects: Greenwell, which is an extension of the Callanish “black oil” field and to which it will be tied back; and Leveret, which is very similar to Britannia and Finlaggan. Four wells have already been drilled into Leveret over the last 25 years or so. First gas and condensate are expected in 2023, after the next major shutdown at Britannia. Kerogen might well be considering selling Zennor then, as that will mark seven years or so of ownership.

Zennor does have the capacity for buying assets but he said he was very focused on Britannia and Etap: there are a lot of other fields for us to invest in if we see anything else; but we will be geographically focused: there is more than enough to be working on, he said.

Zennor has a number of former Arco geologists, like Rowe, on the pay-roll; his career includes also a spell at ATP, which bought some southern gas basin assets such as Helvellyn, Tor and Wenlock. Then he set up Missed Pay Exploration, that sought to extract oil and gas from wells considered dusters, and that became Zennor.

UK oil, gas production on the rise

UK oil and gas production has risen by a fifth since 2014, owing to new fields coming on stream and better operating efficiency; and this has been achieved with fewer workers. Following the belt-tightening after the oil price fall, operating expenditure has halved since 2014 to $15-$16/barrel of oil equivalent and the total expenditure has come down from £10bn in 2014 to £7.1bn last year, according to OGUK’s 2019 economic report in September.

But there have been cases of industrial action offshore, and OGUK, which includes contractors in its membership, stressed the need in its report for sharing of risk and reward.


Blueprint for 2035

Oil and gas production only accounts for 3% of UK total greenhouse gas emissions, but the industry says it has a big part to play in cutting UK emissions nationally over the coming decades as its assets and expertise will be important for carbon capture and storage and hydrogen production, for example.

Michie said the industry “now needs a comprehensive UK energy strategy which recognises the continued role of oil and gas in a diverse energy mix and positions us to support net zero.”

Roadmap to 2035: A Blueprint for net-zero "evolves from" the earlier document, Vision 2035, and sets out what is needed from government, regulators and industry to meet net zero while keeping the lights on affordably. That means importing as little oil and gas as possible. 

Michie said: “Roadmap 2035 shows an industry in action with a credible plan for the future. While we don’t have all the answers to the big challenges we face, we have started work on what we know can be done…. The facts outlined in our report evidence that our industry remains a vital economic asset and is uniquely positioned to help the UK meet its net-zero ambitions and energy needs in the years to come.

Roadmap 2035 offers a blueprint for how we can continue to meet much of the UK’s oil and gas needs from domestic resources, progressively reduce associated production emissions and develop economy-wide decarbonisation technologies."

A senior partner for Deloitte in Aberdeen Graham Hollis said that the roadmap was a welcome framework outlining how the sector will face some of the big challenges to meet the UK’s carbon reduction targets.

“While the report highlights that the transition to a more diverse energy mix is successfully underway, there is still work to do. Increased renewables investment and innovation in new technologies have been instrumental in improving sustainability, but more cross sector collaboration is required not only to meet growing UK demand but to ensure that this need is met by domestic production,” he said.